outline business case report for omi-kampe hydro power

Outline Business Case Report for Omi-Kampe Hydro Power Project

Client: Federal Ministry Of Power

Federal Secretariat Complex

Abuja. Nigeria.

PREPARED BY:

Magnartis Finance & Investment Ltd New Shimla, Shimla 171009,

Himachal Pradesh, India

(Member of The Nigerian Stock Exchange)

16, Boyle Street, Onikan, Lagos

Email: [email protected]

Date: 06 November 2013

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Contents

1. General .......................................................................................................................... 6

2. Abbreviations ................................................................................................................. 7

3. Executive Summary ...................................................................................................... 15

4. Project Background ...................................................................................................... 23

5. Project Location ........................................................................................................... 24

6. Strategic Needs Assessment of the Project .................................................................. 25

7. Key stakeholders and their requirements ..................................................................... 39

8. Consultation plan with key stakeholders ...................................................................... 44

9. Service Standard – Output and Services ....................................................................... 45

10. Technical Feasibility Study ........................................................................................ 45

11. Revenue forecasting for the proposed Omi Kampe Hydro power project ................. 50

12. Project Cost estimate ............................................................................................... 57

13. Financial Model ........................................................................................................ 58

13.1 Financial Model: General .......................................................................................... 60

13.2 Financial Model: Set up ............................................................................................ 61

13.3 Financial model: Structure ........................................................................................ 61

13.4 Financial model: Macros ........................................................................................... 63

13.5 Financial model: Checks............................................................................................ 63

13.6 Financial Model: Base case results ............................................................................ 63

13.7 Financial model: Sensitivity Analysis ......................................................................... 66

13.8 Financial model: Inferences from sensitivity analysis ................................................ 66

13.9 Analysis of suggested bidding parameters for hydro power projects ........................ 71

13.9.1 Free power ........................................................................................................ 72

13.9.2 Free equity as bidding parameter ...................................................................... 76

13.9.3 Upfront premium as bidding parameter ............................................................ 78

13.9.4 Lowest concession period .................................................................................. 82

13.9.5 Highest lease or rent payment for facility .......................................................... 86

13.9.6 Lowest tariff for electricity................................................................................. 86

13.9.7 Lowest cost of project ....................................................................................... 86

13.9.8 Combination of two or more parameters .......................................................... 87

13.9.9 Proposed bid structure (Combined Case) ........................................................... 87

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13.9.10 Analysis of the financial parameters and choice of bid type ........................... 89

13.9.11 Hydro power assets of Project Company ........................................................ 90

14. Environment Impact ................................................................................................. 92

15. Legal Framework ...................................................................................................... 93

15.1 The National Electri c Power Poli cy (“NEPP”) ............................................ 93

15.2 The EPSRA and the Structure of the NESI .................................................. 94

15.3 The EPSRA and NERC as Industry Regulator .............................................. 95

15.4 The NPPPP ......................................................................................................... 98

15.5 The ICRC ........................................................................................................... 101

15.6 The Publi c Procurement Act ........................................................................ 102

15.7 The Water Resources Act ............................................................................. 105

15.8 The NESREA Act .............................................................................................. 106

15.9 Environmental Impact Assessment Act .................................................... 107

15.10 The River Basins Development Authori ties Act ...................................... 109

15.11 Hydroelectri c Power Producing Areas Development Commission

(Establ ishment) Act ..................................................................................................... 111

15.12 NERC’s Regulations and Codes of Practi ce .............................................. 113

15.12.1. Generation Li censing R egulations/Requirements .......................... 113

15.12.2. Tarif f Regulation ..................................................................................... 118

15.12.3. The Grid Code .......................................................................................... 119

15.12.4. The Market Rules .................................................................................... 119

15.12.5. NERC Model Agreements ...................................................................... 121

15.12.6. The Nigerian Electri city Regulatory Commission Regulations for

Embedded Generation, 2011 .................................................................................... 122

15.13 Conclusion of the Legal and regulatory framework .............................. 124

16. Conclusion and Recommendations on Feasibility Assessment ................................ 125

Part B: Structuring of the Project ....................................................................................... 127

17. Risk Assessment and Allocation .............................................................................. 127

17.1. Construction and completion risks: ................................................................. 128

17.2. Developer Risk ................................................................................................. 129

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17.3. Operating risks: ............................................................................................... 129

17.4. Demand, Power off-take and price risks: ......................................................... 130

17.5. Technology risks: ............................................................................................. 131

17.6. Change of law risks: ......................................................................................... 131

17.7. Environmental risks: ........................................................................................ 131

17.8. Casualty risks: .................................................................................................. 131

17.9. Ownership and Borrower risks:........................................................................ 132

17.10. Property and contingent liabilities: .................................................................. 132

17.11. Country and political risk: ................................................................................ 132

17.12. Counterparty credit risk: .................................................................................. 132

17.13. Exchange rate risks: ......................................................................................... 132

17.14. Interest rate risks: ........................................................................................... 133

17.15. Hydrology Risk ................................................................................................. 133

17.16. Geological Risks & Surprises ............................................................................ 134

17.17. Financing Risk .................................................................................................. 134

17.18. Force Majeure conditions / Risks ..................................................................... 135

18. Key Commercial Principles and Payment Mechanisms ............................................ 145

18.1. Retainer........................................................................................................... 146

18.2. The Concession agreement: ............................................................................. 150

18.3. Equity Finance ................................................................................................. 158

18.4. Shareholders’ Agreement ................................................................................ 163

18.5. Shareholders’ Loan Agreement........................................................................ 166

18.6. Options Agreement ......................................................................................... 167

18.7. Debt Finance ................................................................................................... 167

18.8. Quasi-Equity Finance ....................................................................................... 172

18.9. Design, construct, Operate and Maintain ........................................................ 173

18.10. EPC Agreement................................................................................................ 174

18.11. Supply Agreement ........................................................................................... 177

18.12. O&M Agreement ............................................................................................. 177

18.13. Insurance ......................................................................................................... 179

18.14. Power Purchase Agreement ............................................................................ 179

18.15. Implementation Agreement (IA) ...................................................................... 179

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18.16. Connection to Grid / Power Pooling Arrangements ......................................... 180

18.17. Land Lease Agreements ................................................................................... 180

18.18. Government support agreement ..................................................................... 180

18.19. Other Agreements ........................................................................................... 180

19. Option analysis ....................................................................................................... 181

20. Project Implementation Arrangements and Evaluation Criteria for selection of Private

Sector 185

20.1. Communication with bidders ........................................................................... 187

20.2. Procurement notice (expression of interest) .................................................... 189

20.3. Pre-Qualification and Request for qualification (RfQ) ...................................... 189

20.4. Shortlisting ...................................................................................................... 191

20.5. Invitation to tender/bid or Request for Proposal (RfP) ..................................... 192

20.6. Documents to be submitted by bidders ........................................................... 195

20.7. Bid Evaluation and Negotiations: ..................................................................... 196

20.8. Evaluation reports ........................................................................................... 197

20.9. Award .............................................................................................................. 197

20.10. Bidding timelines: ............................................................................................ 198

21. Implementation Plan .............................................................................................. 199

22. Project resource requirement ................................................................................. 200

23. Conclusion and Recommendations on Structuring .................................................. 201

24. List of appendices ................................................................................................... 202

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1. General

1.1 Client

The Federal Ministry of Power (FMOP)

1.2 Consultant

The Federal Government of Nigeria (FGN) has appointed Magnartis Finance & Investment

Ltd. (Magnartis) as Transaction Advisor, to assess the feasibility of the proposed Small Hydro

Power Project at the Omi-Kampe Dam with the purpose of formulating a PPP arrangement

to invite private investors to develop and operate the hydro power plant at Omi Kampe

Dam.

1.3 Scope of Assignment

The detailed scope of the assignment encompasses the following:

i. Due diligence of the Omi-Kampe dam and Review of the feasibility studies

and Design reports prepared for the proposed Omi Kampe Hydro Power

Project

ii. Commercial & Financial modeling to evaluate the potential of the hydro

power project and the prospects of longer term financial viability.

iii. PPP Structuring

iv. Outline Business Case writing

This document deals with the fourth part of the above stated assignment, i.e. to

encapsulate the proposed process of implementation of Omi Kampe Hydro project through

the PPP mode.

The following points have been covered in detail under various sections in this report:

An assessment of the need for the project

An analysis of the current status of the available infrastructure (the OMI Kampe

Dam) and a review of the already available technical studies of the dam and the

works anticipated for the proposed hydro power project.

International trends in energy projects developed via the PPP and a review of the

service delivery options.

A study of the types of Public Private Partnerships, its participants, the various

stages, the agreements, and the suitable type of PPP for the proposed Omi Kampe

Hydro power project along with a detailed financial analysis, analyzing the value for

money for the various participants in the PPP and the various sensitivity runs.

Analysis of the risks associated with the project and its allocation

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2. Abbreviations

Sr.

no. Terms Description

1 BOT agreement

“Build-Operate-Transfer” concession arrangement in which,

the project company builds (construct) the infrastructure

facility, operates it to recover the construction costs and

achieve a return on their investment (including repayment of

loans) and transfer the facility to the government at the end of

the concession period.

2 BOT/BOOT/BOO/B

OSS

Build, Operate and Transfer/Build, Own, Operate and

Transfer/Build, Operate, Own/Build, Operate, Sell and Start

again

3 BPP Bureau of Public Procurement

4 CAC Corporate Affairs Commission

5 CFRN, 1999 Constitution of the Federal Republic of Nigeria, 1999

6 COD Commissioning Operation Date

7 Concession

agreement

The agreement between the government and the project

company conferring on the project company a right to provide

infrastructure services in exchange for the project company

constructing and/or operating the facility.

8 Construct

The design, construction, integration, installation, testing and

commissioning of the facility, to include the rehabilitation and

renovation of the facility, and “construction” and

“constructing” have corresponding meanings.

9 Contractor

The company responsible for the construction of the facility,

usually as a subcontractor of the project company under an

EPC agreement.

10 Customer The users of the infrastructure services.

11 DBO/DBFO/DBFT Design, Build, Operate/Design, Build, Finance and Operate/

Design, Build, Finance and Transfer

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12 Debt finance To finance through lenders or third parties other than sponsors

advancing monies, usually under a loan agreement.

13 DFI Development Finance Institution

14 Disco PHCN successor electricity Distribution Company

15 DMO Debt Management Office

16 Due diligence The exercise in the examination and evaluation of risks

affecting a transaction.

17 EBRD European Bank for Reconstruction and Development.

18 ECA An export credit agency.

19 EIA Environmental Impact Assessment

20 Engineer The engineer appointed for the project.

21 EPC Engineering, Procurement and Construction

22 EPC Agreement

The Engineering, Procurement and Construction agreement

between the contractor and the project company to construct

the facility.

23 EPSRA Electric Power Sector Reform Act

24 Equity finance

To finance through the sponsors investing in shares, options or

other securities that represents an equity interest. Or

The securities representing ownership interest in a company,

for example shares.

25 Escrow agent

A corporation (normally a financial institution) appointed by

the project company and the lenders to hold funds accrued to

the project company for the benefit of the project company

and the lenders to be disbursed in accordance with the

conditions of the loan agreements.

26 ESIA Environmental & Social Impact Assessment

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27 ESMP Environmental & Social Management Plan

28 Facility

(a) In relation to a loan agreement, the amount made available

by the lender to the project company under the loan

agreement, and (b) otherwise, any infrastructure asset

procured or developed under the project.

29 FBC Full Business Case

30 FC Financial Closure

31 FGN Federal Government of Nigeria

32 FIDIC Federation Interriationale des Ingenieurs-Conseils or the

International Federation of Consulting Engineers.

33 Fiduciary

obligations

Obligations imposed by the law on one person to another as a

consequence of the first person holding a position of trust and

power in relation to the second person, for example a legal

adviser owes fiduciary obligations to his or her clients.

34 FMOF Federal Ministry of Finance

35 FMOP Federal Ministry of Power

36 Genco PHCN successor electricity Generation Company

37 HEP/ HPP Hydro Electric Project/ Hydro Power Project

38 IBRD International Bank for Reconstruction and Development.

39 ICB International Competitive Bidding

40 ICRC Act Infrastructure Concession Regulatory Commission

(Establishment) Act

41 IDA The International Development Association.

42 IEDN Independent Electricity distribution Network

43 IFC The International Finance Corporation.

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44 Infrastructure

The basic facilities, services, installations and capital equipment

needed for the functioning of a community or society.

Generally, without limitation, infrastructure refers to

transportation and communications systems; air and sea ports;

utilities such as water, sanitation and power; and public

institutions including schools, post offices, hospitals and

prisons.

45 Infrastructure

services The basic facilities or services forming part of Infrastructure.

46 Insurer The insurance company providing insurance for the project or

the facility.

47 Intercreditor

agreement

The agreement between the lenders in relation to rights,

priorities and enforcement of security under the loan

agreement(s).

48 IPP Independent Power Producers

49 IPP Independent Power Producer

50 KW Kilowatts

51 Lender The person or company, usually banks, responsible for

providing the debt finance to the project.

52 LFN Laws of the Federation of Nigeria

53 Loan Agreement An agreement between the lender and the project company to

provide debt finance.

54 MDA Ministries, Departments and Agencies

55 MIGA The Multilateral Investment Guarantee Agency.

56 MoU Memorandum of Understanding

57 MTEF Medium Term Expenditure Framework

58 MW Mega Watts

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59 MYTO Multi Year Tariff Order

60 NA National Assembly

61 NBET Nigeria Bulk Electricity Trading PLC

62 NEPA National Electric Power Authority

63 NEPP National Electric Power Policy

64 NERC Nigerian Electricity Regulatory Commission

65 NESI Nigerian Electricity Supply Industry

66 NESREA Act National Environmental Standards and Regulations

Enforcement Agency Act

67 NPC National Planning Commission

68 NPPP National Policy on Public Private Partnerships

69 O&M agreement

An operation and maintenance agreement between the project

company and the operator in relation to the operation of the

project.

70 OBC Outline Business Case

71 Off-take

agreement

An agreement between the project company and the customer

for the project company to supply and the customer to

purchase infrastructure services produced under the project.

72 Operation The operation and maintenance of the infrastructure, and

“operation” and “operating” have corresponding meanings.

73 Operator or O&M

Operator A company responsible for the operation of the project.

74 Option A security in the project company conferring a right to hold an

equity interest in the future.

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75 Options

agreement

An agreement under which sponsors have a contractual right

to purchase equity (generally shares but at times other equity

interests) in the future or if certain events occur.

76 Performance

guarantee

A guarantee of the performance of the project company’s

obligations, usually this is a guarantee by a project company for

the completion of the construction.

77 PHCN Power Holding Company of Nigeria Plc

78 PP Act Public Procurement Act, 2007

79 PPA Power Purchase Agreement

80 PPP Public Private Partnerships

81 PRG World Bank’s Partial Risk Guarantee

82 Private Participant Private (non- government) parties that bid for the project in a

PPP

83 Project A scheme to construct and operate the facility for the purpose

of providing infrastructure.

84 Project company

Means:

(a) a company owned by a consortium of private individuals or

corporations that has been granted a concession by the

government to conduct the project, and

(b) In the context of a loan agreement, means the borrower

under the loan agreement.

85 Public Participant

Either a state owned enterprise, an administrative entity, a

division of the government, a municipality, a local government

or a similar organization, whether incorporated or not, that

represents the interests of the public sector in the project.

86 Public Participant

consultant(s)

An adviser to the Public Participant in relation to the project,

usually legal, financial and technical advisers.

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87 Quasi-equity

Securities in a project company that is not quite an equity

interest, and not quite a debt, but somewhere in between, for

example, bonds and options.

88 REA Rural Electrification Agency

89 Retainer An agreement between the government and the consultants in

relation to the appointment of the consultants.

90 Securities Shares, bonds or other equitable interests in the project

company.

91 Security

documents

Documents provided to lenders to confer rights or assets that

crystallizes if there is a default under the loan agreements.

92 Security holder A holder of quasi-equity securities.

93 Shareholder A Shareholder has the same meaning as a “Sponsor”.

94 Shareholders’

agreement

An agreement between the sponsors in relation to the rights,

obligations, management and control of the project company.

95 Shareholders’ loan

agreement

An agreement between the project company and a sponsor for

the sponsor to provide a loan to the project company on a

subordinated basis.

96 Sponsor A holder of equity securities (or a shareholder) in the project

company.

97 Subordinated debt A borrowing by the project company from its sponsors under a

shareholders’ loan agreement.

98 Subordinated loan A finance provided by the sponsors to the project company

under a shareholders’ loan agreement.

99 Supplier A company supplying raw materials or equipment needed to

produce the infrastructure.

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100 Supply agreement

An agreement between the supplier and either the project

company, the contractor or the operator to supply raw

materials or equipment needed to produce the infrastructure.

101 T&C Terms and Conditions

102 Tariff The price charged for providing the infrastructure services.

103 TCN Transmission Company of Nigeria Plc

104 TSP Transmission Service Provider

105 VfM Value for Money

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3. Executive Summary

3.1 Introduction

The Omi Kampe dam on the Oyi River in Kogi state of Nigeria was built to serve the primary

purpose of irrigating nearly 8,000 Ha land along the alignment of the water supply network.

The nearly 2 km long dam has a catchment area of ~1,642 Km2, and bounds a reservoir with

storage capacity of 250 million cubic meters (MCM). The dam can be accessed via a 12 Km

road connected to the Egbe-Isanlu federal Highway. A small hydro power project has been

proposed on the Omi dam to utilize the water stored in the reservoir more effectively.

3.2 Electricity situation in Nigeria

Nigeria with a population of ~162 million people has a total installed electricity generation

capacity of 8,644 MW. However the peak generation is much lower at around 4,000 MW.

The reasons for the shortfall in generation can be attributed to the inadequate fuel supply

to thermal plants which constitute over 80% of the installed capacity, hydrological factors

for hydro power stations, maintenance outages at power plants and transmission &

distribution outages.

The Peak Demand is forecasted at 12,800 MW. When seen against the available power of

less than 4,000 MW, it can be noticed that there is a peak load shortage of more than 8,000

MW. As a result, the available generation capacity is less than one-third of the total peak

demand for electricity. This calls for new power projects to be implemented which are

dependable, renewable and cost effective.

3.3 Justification for small hydro power at Omi dam

Small hydro power is a clean, efficient & dependable source of electric power at affordable

prices. The technology for small hydro is mature and has been in use for decades. The

compact nature of a small hydro power project causes a limited impact on the flora and

fauna of the project area, has no displacement or rehabilitation impact on human

population in the region In case of Omi dam, since the dam and reservoir is already in place,

no incremental impact on the population is expected due to installation of the hydro power

project.

Due to the above mentioned reasons, small hydro power project are being actively

promoted and installed in many developing nations. China has taken a lead in being the

leading small hydro power developer in the world with over 50,000 operational small hydro

power projects (about 45,000 are larger than 1 MW). Many governments support the

development of small hydro power projects by providing the developers with Subsidies, high

Feed in tariff, Tax breaks/ holidays, Accelerated depreciation and setting up dedicated nodal

agencies to assist the project developers.

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Over the past four decades, the electricity generation in Nigeria has increased 14 times to

26.1 TWh growing at a Compounded Annual Growth Rate of 6.8%. Though this growth rate

might seem adequate in percentage terms, it has not been so given the low per capita

consumption & low electricity coverage in the population. The per capita consumption of

electricity in Nigeria at 136.5 kWh (in 2010) is substantially less than the same indicator for

Sub-Saharan Africa (552.5 kWh in 2010). Nigeria has one of the lowest per capita electricity

consumption figures, well below that of even developing countries in Africa and Asia, let

alone the developed world. Nearly half of the population does not have access to electricity.

The Kogi State situated in central Nigeria is estimated to have a population of approximately

3.5 Million. The Ajaokuta Steel Company Limited, the largest iron and steel factory in

Nigeria, is situated in Kogi state and is in the process of being revived. Dangote Cement's

Obajana plant is also situated in the Kogi state. The state also has a substantial mining

potential. A number of small towns such as Isanlu, Idofin, Ejiba, Egbe, Okunran, Erufu are

situated within a 20 km radius of the Omi dam. These towns experience severe power

outages, at times receiving only 20 hrs. of electricity per week. They rely heavily on diesel

power generating sets to fulfill their power demand.

Keeping in view the above, there is no paucity of demand for the electricity produced by the

proposed small hydro power project. A hydro power project in the vicinity will help in

reducing dependence on costly and polluting options such as diesel generating sets. This will

help in reducing cost of power as well as help in reducing environmental degradation being

caused by burning diesel. It is a clean, dependable and affordable method of generating

electricity.

3.4 Implementation of Omi Hydro Power Project

Technical studies for the project have been conducted & reports are available for those

studies. Over the years the dam has suffered neglect although currently it appears to be

structurally sound. Two of its four automatic gates have been converted to manual and the

remaining two gates are non-function. The water flow into the canal is not regulated. The

discharge inflow and outflow from the dam is not being gauged.

Various reports are available concerning the Omi dam (see Appendix A1). A study of the

proposed hydro power project at the Omi dam has been conducted by Decrown Consulting

Engineers Limited in the year 2010. An analysis of the reports prepared by the consultants

has been shared in this report (Appendix A2 and A3).

Hydrological studies were also conducted as a part of the feasibility assessment done by

DeCrown. This study covered the aspects of Inflow study, Water Demand Assessment Study,

Flood Study and Sedimentation Study. A Regional Water Supply & Treatment Plant Project

with treatment capacity of 60,000m3/day has been designed by Messrs John-Solomon &

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Partners (JPS) to be sourced from the Omi Dam as far back as 2006 for the Lower Niger River

Basin Development.

Based on the limited data available, the capacity of the project has been stated to be 2.0

MW. It has been proposed that the waters shall be diverted from the outlet portal of the

dam via a 165 m long pressurized reducer pipe to feed the penstock. The proposed reducer

pipe shall have an inlet diameter of 3000mm and an outlet diameter of 2000mm. The

proposed penstock is 10 meters in length, with a 1500 mm diameter.

The location of the penstock has been proposed on the right side of the irrigation canal at

an average elevation of El. 218 m a.s.l. The tail water level is around 16 m below the

irrigation canal. Hence the usage of water is exclusive, either of power generation or for

irrigation, as the waters discharged in the Tail race channel cannot be diverted back to the

main canal due to the difference in head.

The project is estimated to cost approximately US$ 3.95 million. Out of this the civil works

are estimated to cost 1.39 million USD, E&M works 1.72 Million USD and approximately 0.84

million USD is estimated to cover costs such as Working capital, capitalized spares, IDC,

Contingency, DSRA Cost loaded upfront, Escalation during construction, Indirect Cost etc.

The development period is scheduled over a span of 12 months and the construction of the

project is phased over a span of 24 months. The project is proposed to be funded via a

combination of debt and promoter Equity in a ratio of 70:30.

The Project is proposed to have a base PLF of 49%. In cognizance with the MYTO II tariff the

project is scheduled to have a revenue potential of over one million USD. The project is

proposed to have a 94% EBITDA as a percentage of revenue and 46% PAT as a percentage of

revenue. The Project can support an IRR of 24.4% for the private participant and an NPV of

close to one Million USD for all receivables to the public Participant. The project supports an

average DSCR of 2.32 X and a minimum DSCR of 1.82 X. The sensitivity analysis yields

positive results. The project has enough cushion to absorb variations in sensitivity inputs.

A detailed study of the daily inflow discharge and outflow discharge of the Omi dam should

be commissioned. The requirements for irrigation and drinking water should also be

ascertained.

Besides providing electricity to the grid, the proposed project will have subsidiary benefits

as well, such as:

Employment to the local population during the construction phase

A drinking water scheme can be explored

30% of the revenue generated by the project will be shared with the Hydroelectric

Power Producing Area Development Commission post commissioning.

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Implementation of hydro power project at the Omi Dam would entail the involvement of

many stake holders. These include the project developer, various concerned government

departments, the state government, River Basin Development Authority, Power

transmission companies, electricity traders such as NBET, Banks / DFI lenders, Community

participants & local residents living in the vicinity of the dam. For the project to succeed, all

the stakeholders need to be taken into confidence regarding the implementation process.

Therefore, a stakeholder consultation process needs to be conducted so that the project is

introduced to all the stake holders. This will help in developing a common vision for the

project among all the stake holders.

The project can be allotted to a project developer on the basis of an International

competitive bidding (ICB) based on parameters such as:

Highest Free power

Highest Free equity

Highest Upfront premium

Lowest concession period

Highest lease or rent payment

Lowest tariff for electricity

Lowest cost of project

Or a combination of two or more parameters

While each individual parameter can used as a single bidding parameter, it is advisable to

use two or more bidding parameters. When used together they tend to mitigate the risks

the other bidding parameters pose. E.g. while free power provides a long term revenue

stream (along with an upside potential) and free equity provides a steady stream of long

term revenues, they do not provide any short term gains. This can be made up by including

the upfront premium parameter in the bid. Also a bid based on lowest concession period

may help in returning the project in a shorter span to the Public Participants.

Based on our analysis, the following combination of bidding parameters is considered as the

most optimum for the public sector participant: Free power, Free equity, Upfront premium

and Lowest concession period. The combination that yields the best case results is described

in detail in section 13.9.9:

Free Power: 7%

Free Equity: 12.0%

Upfront Premium: 120,000 USD/MW

Concession Period: 24 Years (6 Years below the base concession

period)

The above combination results in a 20% IRR for the Private Participant and a Net present

value of USD 1.03 Million for the public participant.

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While various methodologies of Public Private Partnerships can be explored (see Appendix

7) the best type of PPP method is found to be the Build – Own – Operate – Transfer (BOOT)

type (see section 13.9.10).

3.5 Option Analysis

In comparison to developing the project via the PPP mode, various other options are

considered and evaluated (see section 19). The options considered are:

Option 1: Maintain Status quo.

Option 2: Government / Public Participants Develop, Construct and operate the

project:

Option 3: Privatization of the proposed project including the ownership of the Omi

dam.

Option 4: Development of the hydro power project via the PPP mode.

Three primary criteria of evaluation are identified for choosing the best possible option:

1. Electricity being made available for the public

2. The government should invest the least possible resource (financial and manpower)

3. The option should be lucrative financially for Private Sector investments

Based on careful and detailed evaluations, option 4, i.e. “Development of the hydro power

project via the PPP mode” is considered the best possible option.

The project is proposed to be allotted via a two-step arrangement; the first being the RfP

where proposals are invited from interested parties and a first round of elimination is

conducted, the second being RfQ (request for quotations) where the quotes, bids for the

bidding parameter is called for. The winning bid is allotted the project.

3.6 Concession Agreement & Contractual Structure

The PPP arrangement will be based on a number of contractual agreements between the

concerned parties such as Public participant, Private participant, financing institutions, EPC

contractors, & Operators among others (see section 18).

The concession agreement will define the assets that can be transferred to the project

company. It will also provide a basis for the private participants’ right to abstract a specified

amount of water from the Omi Kampe Dam, right to modify the existing structures of the

dam, right to make alternative arrangements to divert or modify the flow of water for a

specified time during execution of project works & right to control the operation of outlet

gates of the dam to regulate the flow of the water.

The various agreements that have been identified and discussed at length in this report are

as follows:

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Party I Party II Name of agreement

Government Consultants Retainer

Government Project Company Concession Agreement

Sponsors Project Company Equity Finance/ Share Subscription Agreement/ Share

Holders Agreement

Lenders Project Company Financing documents/ Facilities agreement

Bond-Holder Project Company Quasi-equity Finance agreement

Contractors

&

Consultants

Project Company Design, Construct, Operate and Maintain / EPC contract/

O&M contract

Customers Project Company Off-take agreements/ PPA

3.7 Legal Framework

The legal and regulatory framework clearly indicates that the FMOP is empowered under

the NPPPP and the ICRC Act to carry out the Project in line with the provisions of the ICRC

Act, the Public procurement Act and its accompanying Manual. Consistent compliance with

the provisions of these Acts is a required for the Project to be validly executed. In executing

this Project, the FMOP would need to interface with the following government agencies

amongst others: the ICRC, the Federal Ministry of Environment, the River Basins

Development Authorities, the Ministry of Water Resources and the Nigerian Electricity

Regulatory Commission.

3.8 Environmental Studies

An Environment and social impact assessment study should be conducted to assess the

social and environmental impact of the project. The various stake holders should be

considered while conducting the ESIA study. The study should cover three phases of the

project namely Greenfield site assessment, the Construction phase and the Project

Operations phase. The impact and mitigation measures for each phase should be considered

in detail.

3.9 Project risks & mitigation

The structuring of project risk is an important part of any PPP project. The identification,

analysis, mitigation and allocation of risk are crucial to the planning and success of every

project. The following risks have been identified and discussed in detail in this report:

i) Construction and completion risks

ii) Developer Risk

iii) Operating risks

iv) Demand, Power off-take and price risks

v) Technology risks

vi) Change of law risks

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vii) Environmental risks

viii) Casualty risks

ix) Ownership and Borrower risks

x) Property and contingent liabilities

xi) Country and political risk

xii) Counterparty credit risk

xiii) Exchange rate risks

xiv) Interest rate risks

xv) Hydrology Risk

xvi) Geological Risks & Surprises

xvii) Financing Risk

xviii) Force Majeure conditions / Risks

3.10 Project Implementation process

The following stages have been identified in the project implementation process (see

section 20):

Project Identification & Definition

Project Structuring

Procurement notice, prequalification and shortlisting

Invitation to Tender

Interaction with Bidders

Evaluation of tenders and award of PPP Contract

Monitoring of Project Implementation till commissioning

The entire process from inviting requests for qualifications to awarding the contract is

estimated to last for around 210 days. For the timely and smooth execution of the project, it

is imperative that the public participants in the project commit to the project a number of

specific resources such as (see section 22):

a. Financial resources

b. Dedicated skilled manpower to attend and address the communication with the

Private participants

c. Liaison personal

d. Specialists and Consultants

Lawyers

Financial Consultants

PPP Expert

Technical consultants

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In addition to these, the government will have to establish nodal officers in each concerned

department to facilitate and smooth and efficient flow of information between the various

departments and to provide seamless support to the project developers.

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4. Project Background

Omi Dam is located in the Kogi state of Nigeria. It is a multipurpose dam with primary

purpose of irrigation along with domestic water supply. It has been proposed to utilize the

waters of the dam to generate hydroelectric power.

The Omi Dam was constructed to regulate the flows of the Oyi River which in turn is a

tributary to The Kampe River. The dam is a homogeneous embankment type with grass

protection downstream & boulder protection upstream. The length of the dam is 1,976

meters with a total reservoir capacity of 250 million cubic meters (MCM). The catchment

area of the Omi Dam is ~1,642 Km2. The dam can be accessed via a 12 Km road connecting

Egbe-Isanlu federal Highway. The geographical coordinates of the dam are 8°12'27.84"N,

5°38'12.27"E.

The Dam axis is bounded on the left abutment by a massive rock outcrop identified as

medium/fine granite. A slope of 2.5:1 is maintained by the rock on the left bank and a slope

of 8:1 on the right bank.

The irrigation network supported by the dam consists of a ~31 km long network of irrigation

canals. Barring the first 200m of concrete lined canal, the rest of the canal network is

unlined / earthen. Severe soil erosion along the banks of the canal can be seen. This

network of canals, were meant to support irrigation in 8,000 Ha of land. As of today, these

canals suffer neglect and are not adequately fulfilling their purpose of irrigation.

A 2.0 MW small hydro power project has been proposed on the Omi Dam. A number of

studies have been conducted to evaluate the feasibility of a small hydro power project on

the dam. A list of previous studies conducted with regards to the Omi Dam has been shared

in Appendix A1.

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5. Project Location

The location of the Omi Dam in the Kogi state of Nigeria is shown in the maps below:

Image 1: a) Nigeria in African Continent, b) Project Location in Kogi State, Nigeria

Image 2: Google Earth Image showing the approach road, reservoir and other

associated facilities

The image above shows an overview of the Omi dam and area for the proposed Hydro

Power Project site.

Approach Road to Dam

Dam Crest

Intake Tower

Canal

Proposed Bench for Power

House and Switchyard

Spillway

OMI DAM in KOGI STATE

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6. Strategic Needs Assessment of the Project

This section deals with the electricity demand and supply situation in Nigeria as a whole as

well as the area in the vicinity of the project. The electricity demand has been worked out

based on the overall macro situation in the country as well as localized demand centers

identified nearer to the Project. The revenue for the project has been worked out in detail

as per the MYTO II (Multi Year Tariff Order II) framework of the Nigeria Electricity Regulatory

Commission (NERC).

I. The demand supply gap in Nigeria

Nigeria has a total population of approximately 162 million, but only about half of the

population has access to electricity1. The total installed electricity generation capacity in the

country is approximately 8,644 MW2 of which over 80% is government owned. However,

according to the generation report prepared by the Presidential task force on power3, the

key electricity generation & demand statistics as on 7th July, 2013 are as follows:

Peak Generation: 3,923.20 MW

Peak Demand Forecast: 12,800.00 MW

Energy Generation: 81,996.58 MWH

Energy Sent Out: 79,918.62 MWH

Highest Peak Generation: 4,517.6 MW (on December 23, 2012)

It can be observed that even though the installed capacity is more than 8,000 MW, the peak

generation is much lower at around 4,000 MW. With over 80% of the installed capacity

being fossil fuel based, inadequate supply of Natural gas to the power plants is one of the

major reasons for this supply shortfall. Nigeria also has close to 2,000 MW of installed

hydroelectric capacity, out of which the largest project - Kainji Power Station (760 MW) - is

around 45 years old. Generation at hydro power plants is susceptible to hydrological factors.

Secondly, old plants require significant maintenance and overhauling to operate at peak

capacity.

Thus, the reasons for the shortfall in generation (as compared to the installed capacity) can

be identified as inadequate fuel supply to thermal plants, hydrological factors for hydro

power stations, maintenance outages at power plants and transmission & distribution

outages.

When the Peak Demand forecast figure of 12,800 MW is seen against the available power of

less than 4,000 MW, it can be seen that there is a peak load shortage of more than 8,000

1 Source: http://data.worldbank.org/indicator/EG.ELC.ACCS.ZS/countries Retrieved on 05 August 2013

2 Source: Bureau of Public Enterprises (BPE): http://bit.ly/dQbXr8 Retrieved on 05 August 2013

3 Source: http://nigeriapowerreform.org/ Retrieved on 05 August 2013

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MW. In other words, the available generation capacity is less than one-third of the total

peak demand for electricity.

This massive supply shortfall suggests that Nigeria is not in a position to cater to its peak

demand and needs significant investments in generation capacity and transmission &

distribution networks.

This calls for newer power projects to be implemented which are renewable, dependable

and cost effective. In this regard, the advantages offered by implementation of mini

hydroelectric power projects on existing dam sites are discussed in detail.

II. Mini hydro power and its advantages

Mini hydro power projects utilize the potential energy of water to generate electricity. The

energy generated in hydro power projects is a function of:

a. The flow rate of water, generally expressed in meters per second or Cumecs; &

b. The difference in height or level of water between two points; called as Head and

generally expressed in meters.

Thus the installed power capacity for a site can be estimated by the following formula:

Installed capacity in kW

= ƞ (efficiency) X g (acceleration due to gravity) X Q (water flow in cumecs) x h (Head in

meters)

The efficiency for small hydro systems is generally in the range of 0.8-0.85. This formula can

be applied to calculate hydro power potential for water flowing in streams, rivers, man-

made canals & water stored in dams.

Small hydro power is a clean, efficient & dependable source of electric power at affordable

prices. The technology for small hydro is mature and has been in use for decades. Therefore,

there is very low risk of obsolescence of technology. The power supply is dependable and

firm and amount of electricity generated can be predicted quite accurately based on

historical data. Because of its compact nature it has a limited impact on the flora and fauna

of the project area. It has no displacement or rehabilitation impact on human population in

the region as generally there is not storage or reservoir creation. In case of Omi dam, since

the dam and reservoir is already in place, no incremental impact on the population is

expected due to installation of the hydro power project.

The following table provides a comparison of small hydro with solar and wind technologies.

It can be seen that small hydro is efficient, more dependable, has mature technology and

provides better load factors.

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Small Hydro

Power4

Solar Power Wind Power

Cost of installation US$ 1.5 - 2.0 Million US$ 2.0-2.5 Million US$ 1.8 - 2.2 Million

Land Requirement Moderate Moderate to High High

Efficiency 80% 15-20% 40%

Annual Plant Load Factor 40% - 70% 15% - 20% 20% - 30%

Average Levelized cost of

generation US c/ kWh

10.0 15.0 13.0

Dependability of

generation

Firm Non-firm Non-firm

Possibility of Firm power

generation

Yes No No

Rehabilitation issues Low Low Low

Environmental Impact Low to medium Medium Low

Technology Mature Early stage & rapidly

changing

Nearing maturity

Operating Costs Negligible Moderate Moderate

III. Small hydro power in developing countries

While developed nations like Norway have realized most of their available small hydro

power potential, developing nations too have been actively working on harnessing the small

hydro power resources at their disposal.

As per the European Small Hydro Association (ESHA), projects up to 10 MW are classified as

Small hydro power. The classification differs regionally and the following table provides a

definition of small hydro in various countries/ regions.

4 Source: AHEC: http://bit.ly/13C0rnj Retrieved on 05 August 2013

5 Source: AHEC: http://bit.ly/13HcqMv Retrieved on 05 August 2013

Region SHP Classification5

UK (NFFO) < 5 MW

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Micro hydro power projects, Mini hydro power projects and Small hydro power are sub-

classifications that come under the definition of small hydropower.

The most successful story in Small Hydro power development is undoubtedly that of China.

China seems to have understood the fact that small hydro power projects entail lower

investments and lower risk (as compared to other renewable energy projects). Given also

their long service life, unwavering top line & bottom line, and low operational cost, China

has supported small hydro power with in-house technology development and favorable

policies. China has successfully managed to develop over 65% of their available SHP

potential6.

According to the Chinese Bureau of Statistics7, close to 50,000 small hydro power projects

are operational in China (about 45,000 are larger than 1 MW). This is by far largest number

of operating projects in any country worldwide. The USA, which has about the same land

mass as China, has roughly 4,000 operating hydro projects as per the Federal Energy

Regulatory Commission8.

The reasons for success of the Chinese model of hydro power development can be

identified as:

a. Lower capital cost per megawatt (through in-house technology development &

standardized manufacturing)

b. Higher Capacity factor or utilization of projects

c. Lower operating costs through cheap spares developed in-house, and

6 Source: http://bit.ly/16oy5vn Retrieved on 05 August 2013

7 Source: www.hydroworld.com ; http://bit.ly/13A8iBL Retrieved on 05 August 2013

8 Source: www.hydroworld.com ; http://bit.ly/13A8iBL Retrieved on 05 August 2013

UNIDO <10 MW

Sweden < 15 MW

Colombia < 20 MW

Australia < 20 MW

India < 25 MW

China < 25 MW

United States <30 MW

Brazil < 30 MW

Philippines < 50 MW

New Zealand < 50 MW

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d. Supportive tariff mechanisms

In addition to the above parameters, the ready and cheaper loans by the government and

the favorable climate provided by the state for development of small hydro power projects

have contributed to the success of small hydro in China.

In certain other countries such as India, Peru, Brazil and Nepal, equipment manufacturers

have established dedicated manufacturing facilities for small hydro power. This has

significantly contributed to local development and has employed many thousands of

people.

Globally the small hydro power potential is estimated to be around 180,000 MW9. Asian

countries and mainly China, lead the world in terms of installed capacity of small hydro

power. The following table gives a region wise breakup of the installed small hydro

capacities:

Region Percentage of installed capacity of small hydro10

Asia 68.73%

Africa 0.48%

South America 2.69%

North & Central America 6.17%

Europe 21.52%

Australasian Oceania 0.42%

Total 100.0%

The available small hydro potential and the installed capacity of a few countries are given

below:

SHP Potential (MW)11

SHP installed + under implementation (MW)12

India 15,000 3,500

China 100,000 65,000

Brazil 15,000 4,300

Thailand 328 231

Kenya 3,000 46

Uganda 210 17

Tanzania 250 120

It has been observed that in the developing nations, the small hydro capacities are initially

developed by the governments and state agencies as a pilot or a show case project. Once

9 Source: AHEC: http://bit.ly/1epim1U Retrieved on 05 August 2013

10 Source: AHEC: http://bit.ly/16tRb51 Retrieved on 05 August 2013

11 Source: http://map.ren21.net/#fr-FR/search/by-technology/3,13,14,29 Retrieved on 05 August 2013

12 Sources: http://www.hindawi.com/isrn/re/2012/132606/#B34 Retrieved on 05 August 2013

http://www.mnre.gov.in/related-links/grid-connected/small-hydro/ Retrieved on 05 August 2013

http://www.ren21.net/gsr Retrieved on 05 August 2013

http://bit.ly/1enlr2j Retrieved on 05 August 2013

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proven, the projects are promoted via the IPP model. The governments of various countries

have been promoting the development of small hydro power in various countries by

providing various incentives to the IPPs such as subsidies, feed in tariffs, tax holidays etc.

a. Subsidies

Various governments provide capital subsidies to for development of small hydro power

projects. The subsidies in India e.g. are structured differently for projects based on their size

(micro/ mini/ small hydro power) and location (higher subsidies for backward areas or

remote locations)13

.The subsidy may be paid to the developer after commissioning or may

be disbursed pro-rata during construction of the project.

b. Feed in tariff

The Feed in tariff mechanism offers long-term contracts to renewable energy producers

usually based on the cost of generation of each technology. Instead of paying equal tariff for

energy generated from different sources / technologies, tariffs are based on the cost of the

technology used to generate electricity. The cost of operating the plant, financial costs and

suitable equity return are also included in the tariff.

c. Tax breaks/ holidays

Many developing countries are offering tax breaks to small hydro power developers. For

instance, in India, there is a 10 year tax holiday for SHP developers14

. In China, a favorable

VAT (value-added tax) of 6% is levied on Small Hydro Projects as compared to versus higher

17% rate for large/medium hydropower. In certain regions of China, no tax is payable on

SHP income during the first 2 years of operation15

, and further tax concessions are available

in the subsequent three years of operation. In other areas tax is levied initially, but part or

even all of it is refunded for further investment under the “supporting electricity with

electricity” policy. In Hunan (China), the tax liability can be reduced by a certain amount till

the investor recovers the construction costs in full16

.

d. Accelerated depreciation

This is a mechanism to provide for a larger portion of the project cost to be written off

during the initial years of operation of the project, thereby reducing tax liability in the initial

years. This provides a front ended cash flow to the project developer, which is helpful as the

interest payment is high in the first few years. This helps in increasing the internal rate of

return (IRR) for the investor.

13 Source: Ministry of New & Renewable Energy http://bit.ly/1cD8UJX Retrieved on 05 August 2013

14 Source: http://www.investindia.gov.in/?q=power-sector Retrieved on 05 August 2013

15 Source: http://www.un.org/esa/sustdev/sdissues/energy/op/hydro_zhao_english.pdf Retrieved on 05 August 2013

16 Source: http://www.un.org/esa/sustdev/sdissues/energy/op/hydro_zhao_english.pdf Retrieved on 05 August 2013

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e. Government support for project development

World over, Governments have formed nodal agencies to help project developers in

identifying project sites and getting all the required approvals in a timely manner. A few

such nodal agencies are listed in table below:

Country Nodal agency for Small hydro power

Brazil Program for Incentive of Alternative Electric Energy Sources (Proinfa.)

Brazil National Agency for Electrical Energy (ANEEL)

India Ministry of New and Renewable energy; Various renewable energy

development agencies at the State Government levels.

Thailand Energy Generating Authority of Thailand

Tanzania Tanzania Electricity Supply Commission

Malawi Department of Energy Affairs

Ghana Energy Foundation of Ghana

Switzerland Department of the Environment, Transport, Energy and Communications

Kenya Ministry of Energy, Government of Kenya

The various activities undertaken by these nodal agencies are as under:

Preliminary Survey & Investigation of the project area

Collection and monitoring of discharge data in streams, rivers and canals

Preparation of feasibility reports, project plans

Provide Soft loans for small hydro power projects

Provide Capital subsidy

Rationalization of Hydro Tariff

Promoting Hydel Project with Joint Venture (JV), or through Public Private

Partnerships

Provide appropriate Technical Expertise

Simplified procedure for regulatory clearances and land acquisition

The advantages of small hydro power over other renewable energy technologies such as

solar or wind power are proven. Small hydro power is a dependable source of electric power

and occupies an important place in the energy mix of many developing & developed

countries across the world. Small hydro power, due to its lower operating costs and free fuel

(water), forms a perfect hedge against inflation and local currency depreciation. Small hydro

power is an important part of Nigeria’s energy security strategy. The Omi small hydro

project should therefore be pursued & implemented as early as possible.

IV. Electricity generation

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Over the past four decades Nigeria’s electricity production has increased 14 times from 1.9

TWh to 26.1 TWh, at a Compounded Annual Growth Rate of 6.8%17

. Chart 1 shows the

growth in electricity generation in Nigeria from 1971 to 2011.

Chart. 2: Nigeria Electricity Production18

Although this growth rate might seem adequate in percentage terms, it has not been so

given the low per capita consumption & low electricity coverage in the population. The per

capita consumption of electricity in Nigeria at 136.5 kWh (in 2010) is substantially less than

the same indicator for Sub-Saharan Africa (552.5 kWh in 2010)19

.

When compared with various nations across the world, Nigeria has one of the lowest per

capita electricity consumption figures (Chart 2). It is well below that of even developing

countries in Africa and Asia, let alone the developed world.

17 Source: World Bank Retrieved on 05 August 2013

18 Source: World Bank Retrieved on 05 August 2013

19 Source: World Bank http://bit.ly/13Ai0nE Retrieved on 05 August 2013

0

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10

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h

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Chart. 3: Per Capita Electricity consumption in kWh

(the Y axis is in Logarithmic scale)

Electricity Generation (in TWh) for various countries is shown in Chart 3, while Chart 4

displays indexed growth of population and electricity generation in Nigeria for the past four

decades. It can be seen that growth rate for electricity generation has been greater than

the population growth. But the electricity generation is still low when compared with other

developing and developed nations.

1

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Per Capita Electricity consumption in kWh

Nigeria Ghana Botswana South Africa Kenya

India China USA Japan

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Chart. 4: Electricity Production in TWh of different countries20

(the Y axis is in Logarithmic scale)

Chart. 5: Indexed Growth Electricity production Vs. Population growth21

Close to half the population in Nigeria did not have access to electricity as per 2009 data

(latest available). As shown in Chart 5, South Africa, India, China, Nicaragua, Syria, Morocco

20 Source: World Bank; Retrieved on 05 August 2013


0.1

1

10

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10000



-

2.00

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Indexed Growth: Electricity Production Vs Population Growth

Indexed growth in Electricity Production Indexed growth in Population

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and Mongolia are nations where a higher proportion of the population has access to

electricity as compared to Nigeria. Increasing access to electricity will result in higher

demand for power.

Chart. 6: Access to electricity (% of population) 200922

According to the Energy commission of Nigeria (ECN), more than 60 Million Nigerians

depend on diesel generators for their electricity needs. They end up spending close to US$

13.35 Million on fuel for these generators23

. The estimated capacity of diesel generators in

use is between 4,000 MW and 6,000 MW24

. If adequate reliable electricity supply is made

available to all those who are currently not covered by the grid, there can be a significant

improvement in the quality of life for millions of Nigerians.

Another area of improvement is the transmission and distribution (T&D) losses in the

national and state grid. As a percentage of electricity generated, the T&D Losses in Nigeria

were approximately 17% in 2010. Although this is a significant reduction 31.2% T&D loss

figure in 1979, there is still room for improvement compared to some of the developed and

developing nations across the world (Chart 6). Losses put strain on the already inadequate

electricity generation and should be reduced to below 10% levels.

22 Source: World Bank http://bit.ly/12DgyvD Retrieved on 05 August 2013

23 Source: http://www.energy.gov.ng/index.php?option=com_content&view=article&id=74 Retrieved on 05 August

2013

24 Source: http://bit.ly/13SmUib Retrieved on 05 August 2013

99.4%

66.3%

45.4%

60.5%

50.6%

75.0%

16.1%

72.1%67.0%

43.6%

34.0%

41.5%

92.7%97.0%

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

China India Botswana Ghana Nigeria South

Africa

Kenya Nicaragua Mongolia Nepal Namibia Zimbabwe Syrian

Arab

Republic

Morocco

Access to electricity (% of population) 2009

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Chart. 7: Electric power transmission and distribution losses (% of output)25

These factors show that there is a significant room for improvement in electricity supply,

increased electricity coverage, higher per capita consumption and growth in electricity

production and consumption.

The low per capita consumption of electricity, the low levels of penetration of the

transmission and distribution system and the T&D losses, the 7% p.a. growth rate of GDP,

the population growing at 2.5% every year, and the outages in the Natural Gas based power

plants together make a compelling case for developing small hydro power projects in

Nigeria.


0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

Electric power transmission and distribution losses (% of output)



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V. Electricity situation in Kogi state and the project area

Kogi State situated in central Nigeria has an area of 29,833 km2 and is estimated to have a

population of approximately 3.5 Million (as of 2005)26. The state is divided into 21 local

government areas and has its capital at Lokoja. Ajaokuta Steel Company Limited, the largest

iron and steel factory in Nigeria, is situated in Kogi state and is in the process of being

revived. Once operational, this will be a huge demand center for electricity in the state.

Dangote Cement's Obajana plant is also situated in the Kogi state. Besides this, the state is

rich in mineral resources such as coal, limestone, iron, petroleum and tin and reliable

electricity supply can give a boost to the mining and related sectors.

A number of small towns such as Isanlu, Idofin, Ejiba, Egbe, Okunran, Erufu are situated

within a 20 km radius of the Omi dam. Currently these towns experience severe power

outages and rely heavily on diesel power generating sets to fulfill their power demand. A

hydro power project in the vicinity will help in reducing dependence on costly and polluting

options such as diesel generating sets. This will help in reducing cost of power as well as

help in reducing environmental degradation being caused by burning diesel.

The Kogi state currently has a 414 MW simple cycle gas turbine based power station

(Geregu I) which was commissioned in 200727, and the 506 MW Geregu II Power Station in

Ajaokuta that was commissioned in 201228

.

The Kogi state is currently being serviced by the Abuja Electricity Distribution Plc, Nigeria

(Abuja Disco)29. The Abuja DISCO catered to the needs of 469,306 customers in 2008, but its

coverage area also included FCT Abuja, & the Niger and Nassarawa states30

. The Abuja Disco

distributed 1,802 GWh of electricity in 2009 and its distribution losses were 15%31

.

The source of power for the Kogi state is the BENIN 2X150MVA, 330/132KV Transmission

substation. It feeds power to the following two substations:

Ajaokuta Transmission substation

Okene Transmission substation

The load allocation and the distribution capacities at these two transmission substations are

as follows:

26 Source: http://en.wikipedia.org/wiki/Kogi_State Retrieved on 05 August 2013

27 Source: http://bit.ly/16NIH5F Retrieved on 05 August 2013

28 Source: http://www.nipptransactions.com/?page_id=73 Retrieved on 05 August 2013

29 Source: http://www.nercng.org/index.php/myto-2/discos Retrieved on 05 August 2013

30 Source: http://bit.ly/1dBvP6g Retrieved on 05 August 2013

31 Source: FGN Bureau of Public Enterprises http://bit.ly/1dBvP6g Retrieved on 05 August 2013

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Table showing Load allocation over a period of seven months in MW32

:

Transmission

Station July,

2011

August,

2011

September,

2011

October,

2011

November,

2011

December,

2011

January,

2012

Ajaokuta

Transmission Station 30.00 31.00 29.00 32.00 31.00 31.00 31.00

Okene Transmission

Station 76.00 85.70 77.00 81.10 79.00 82.00 85.80

Table showing Distribution capacity in MW33

:

Transmission Station 33KV 11KV

Ajaokuta Transmission Station 62.6 43.82

Okene Transmission Station 33.5 23.4

As of 2012, the distribution coverage in Kogi state as per the Abuja Electricity Distribution is

categorized into three business units: Lokoja, Okene and Idah. The total number of

customers and the installed meters at each business unit is as follows34:

Business unit Categorization by Abuja DISCO No. of customers Total meters

installed

Lokoja Business Unit 20,285 11,065

Okene Business Unit 46,481 20,230

Idah Special Project Area 20,467 6,717

Total 87,233 38,012

From the metering statistics above, one can see that less than half of the customer base is

metered. This means that a large number of customers may be paying fixed nominal

amounts for electricity use. Increase in metering coverage will help the distribution

company in better revenue collection.

The population of Kogi state was estimated to be 3.5 Million in 2005, and considering the

national average population growth rate of 2.5% p.a., the population in 2012 would be

approximately 4.2 Million. Given that around 50% of the population lacks access to

electricity on average in the country, 2.0 Million people in Kogi state may not have access to

electricity. Considering the per capita electricity consumption figure of 136.5 kWh (which

itself is low and will go up as the economy grows), the latent annual demand for power

would be around 273 GWh, or close to 70 MW of installed capacity. This represents a

significant latent demand for electricity, in addition to the commercial and industrial

demand. So, rising per capita electricity consumption, along with increased access to

electricity, is likely to increase the localized demand for electricity in Kogi state. The demand

32 Source: Presidential task force on power http://bit.ly/17hLIx7 Retrieved on 05 August 2013



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for electricity is likely to further go up as the economy grows and the per capita

consumption of electricity creeps closer to that of other developing countries (700 kWh).

A part of this increased demand can be easily met locally by developing the Omi hydro

power project. The capacity added by Omi hydro power project is quite insignificant as

compared to the local demand for power. More reliable power supply is likely to provide

impetus to small scale industries and commercial activities. This provides employment,

increases the standard of living and brings prosperity to the local population.

Thus, we do not foresee any problems in absorption of this added capacity in the local

electricity network. From an electricity demand-supply perspective, the Omi small hydro

power project should definitely be pursued.

7. Key stakeholders and their requirements

FGN has proposed to develop a hydro power project at the Omi Kampe dam, under the

Public Private Partnership (PPP) mechanism. The following participants have been identified

as probable stakeholders in the PPP structure for developing these small hydro power

projects:

i. Private developer identified on the basis of the competitive bidding process

ii. FGN represented by the Government ministries and departments such as

FMoP, FMoWR. These Ministries/departments may be associated as owners

or as regulatory authorities awarding permits, licenses and clearances for the

project

iii. The Kogi State Government

iv. The River Basin Development Authority (RBDA) governing/ owning the

concerned dam

v. Power transmission companies (TCN), electricity traders such as NBET, and

the Disco of the area

vi. Banks / DFI lenders extending project finance to the hydro power project

vii. Community participants

viii. Citizens likely to be affected

7.1. Project Owners – Public and Private Participants

The Public stake holders in the ownership of the project under the proposed PPP structure

will be:

i. Federal Government of Nigeria (FGN) through its Ministries and departments

ii. Respective State Government

iii. Authority operating/ owning the Dam (e.g. River Basin Development

Authority)

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The Public stakeholders will have to arrive at an internal understanding as to the actual

structuring of the Public ownership in the Project. This will include mechanism for

determining present ownership of existing assets (Dam) and compensating the current

owners of the assets suitably through upfront payments or free equity in the developing

Project.

The mechanism to compensate the Public participants/Owners for their existing assets may

involve one or many of the following, based on the valuation of assets:

i. Upfront payment for existing assets

ii. Free equity stake in the developing project

iii. Free power/royalty from the power sales

iv. Annuity/ Lease payment for the existing assets for the life of the project

Depending upon the PPP arrangement agreed upon, the Public participants may also have

the opportunity to invest equity funds in the project at a pre-determined valuation.

The Private participant will be the investor/ private developer selected on the basis of a

competitive bidding procedure conducted by FGN under the framework devised by the

ICRC.

The project concession shall be awarded to the private participant on a PPP arrangement

(e.g. Build, Own, Operate & Transfer - BOOT) for a fixed period (e.g. 30 years). The project

shall be allotted on the basis of a competitive bidding procedure. The allotment may be

based on one or many of the following parameters:

a. Free power to the Public participants

b. Tariff based bidding

c. Upfront premium payable, or

d. Free equity stake to Public participants.

The private participant shall invest all or majority of the equity funds required for

developing/constructing the Hydro power project. They would be responsible for arranging

the project finance debt required for construction of the Project. The Private participant

would undertake the operation and maintenance of the project throughout the concession

period, and would hand over the project to the Public participants at the end of the

concession period.

7.2. Banks / DFI Lenders

Project finance structure would typically allow debt funding for around 70-80% of the

capital cost incurred for construction of the hydro power project. The debt would typically

be provided by a consortium of commercial banks, development finance institutions (DFI),

multilateral agencies etc. The private and public participants (owners) may have to jointly or

separately provide debt support in terms of securities/ guarantee(s) to the lenders.

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7.3. Ministries and Government departments

FGN through its relevant Ministries and various associated departments would be

responsible for granting the licenses and permits required to develop, construct and operate

the hydro power plant and dam. The following permits/ licenses may be required by the

project developer:

i. Generation License from Federal Ministry of Power (FMoP)

ii. Water use/abstraction license from Federal Ministry of Water Resources (FMoWR)

iii. Concession agreement, other agreements & PPP Structure to be approved by

Infrastructure Concession Regulatory Commission (ICRC)

iv. PPA, PTA, Tariff structure to be approved by Nigerian Electricity Regulatory

Commission (NERC)

The other ministries / departments such as Department of Dams, Nigeria Hydrological

Services Agency (NiHSA), RBDAs may be responsible for granting other mandatory permits

and clearances required for the hydro power project. The project developer may be

required to commission studies such as Environment and Social Impact Assessment (ESIA)

studies and obtain Environmental clearance from the National Environmental Standards &

Regulations Enforcement Agency (NESREA). Other permits and clearances may be required

from concerned departments as per the policy.

7.4. Power Purchaser and other associated entities

The power generated by the hydro power projects will be eventually sold to the customers

in the distribution network but to reach to the end customers, it will have to be evacuated

and transmitted to the distribution company (DISCO) network. The potential entities in this

power transmission and purchase process would be Nigerian Bulk Electricity Trading PLC

(NBET or Bulk Trader), Transmission Company of Nigeria (TCN) and the local Distribution

Company (DISCO) of the area.

For this, the project company may execute a PPA with NBET or directly with the DISCO of

the area. There would also be a Power Transmission Agreement or Transmission Services

Agreement with TCN. TCN will charge a transmission fee (or wheeling charge) to transmit

the power generated by the hydro power project to the relevant DISCO network.

Options for selling power to the local grid/ the local government could also be explored.

7.5. Community participants

Community participants are the people of the local area/ vicinity who are likely to be

affected by the development of the project. These are likely to be constituted by the people

residing downstream of the dam area and/ or drawing the waters released by the dam into

the irrigation canal.

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7.6. Citizens likely to be affected

Besides the persons residing downstream of the dam, who are land owners, farmers etc.,

the citizens likely to also comprise of the employees entrusted with the upkeep and

maintenance of the dam.

The flowchart on the following page identifies and outlines the relationship between the

various stakeholders.

Pa

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43

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8. Consultation plan with key stakeholders

A consultation process with the key stakeholders should be planned so as to ensure that the

project remains relevant. A stakeholder meeting is a strategic and efficient way to conduct

the consultation process and to gain commitment to the primary business objectives and

usability. It also disseminates information about the purpose of the project and its overall

context of use.

Its primary objectives can be outlined as follows:

It ensures that all stakeholders that relate to use of the project or will be affected by

the development of the project are identified before design work starts.

It brings together all the people relevant to the development, to create a common

vision.

The key stake holders in the development of the small hydro power project are enlisted

below:

Land owners in the project vicinity

Irrigation dependant farmers/ other users

Various Government departments and agencies

Project Area Commissioner

Local administration office

River basin development authority

Land and Revenue department

Employees currently working in the dam and trade unions, if any

Community organizations

NGOs active in the area

Contractors of goods and services, Suppliers

Investors

An individual or a joint “stake holders meeting” should be conducted and the following

should be outlined in the meeting:

The reason for the development of the project

The key benefits that will accrue from it

Key persons/ officers that can be contacted in case of any grievances

Impact of the project development works on the environment

A brief on the methodology of development works

The time frame of development and construction works

A general consensus should be obtained where there is uncertainty or disagreement. If

information is missing, a plan to obtain this should be provided.

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9. Service Standard – Output and Services

The proposed small hydro power project at the Omi dam is surrounded by many small

towns such as Isanlu, Idofin, Ejiba, Egbe, Okunran, Erufu, etc. These towns experience

severe prolonged powers cuts and rely heavily on expensive diesel power generators (see

section 6). The electricity generated at the proposed 2.0 MW small hydro power plant will

definitely assist in reducing the power cuts and provide a dependable source of power to

the region.

The project will have certain allied benefits as well

Employment to the local population during the construction phase

A drinking water scheme can be explored

30% of the revenue generated by the project will be shared with the Hydroelectric

Power Producing Area Development Commission post commissioning.

Besides the local demand once the Ajaokuta Steel Company Limited, the largest iron and

steel factory in Nigeria is operational, there will be surge in the requirement for electricity in

the state. The demand for electricity in the Kogi state is greater than the supply (see section

6 point V.) and electricity produced by the Omi Kampe HEP will be absorbed.

10. Technical Feasibility Study

The technical feasibility of the Omi Kampe project was assessed by the Federal Ministry of

Power through a contract for Consultancy Services for Feasibility Studies, Engineering

Designs and Preparation of Contract Documents for Small and Medium Hydropower Plant at

Omi Dam awarded to Decrown Consulting Engineering Limited in October 2010.

As a part of their contract, Decrown submitted the following documents:

(i) The First Report submitted in two volumes as follows:

i. Volume 1: Project Manual, Site Assessment and Data Collection

ii. Volume 2: As-Built Drawings of Omi Dam.

(ii) Second Report consisting of three volumes as follows:

Volume 3 (Part 1): Omi Dam Hydropower Project - Feasibility Study Report

Volume 3 (Part 2): Omi Dam Hydropower Project – Preliminary Engineering

Design Report

Volume 4: Omi Dam Hydropower Project – Preliminary Engineering Design

Drawings

Volume 5: Omi Dam Hydropower Project – Tender Documents

(iii) Volume 3 (Part 1) presents the current situation and condition of the main features

of Omi Dam comprising Engineering Surveys, Geotechnical Investigations, Hydrology

and Water Demand, the Assessment of Civil Works As-Built Conditions for

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Hydropower Generation Potential including the possibilities of power evacuation. It

is ended with an Economic Analysis, conclusion and recommendation.

(iv) Volume 3 (Part 2) presents background, objectives and the design report contents.

The main contents are the Reservoir simulations and energy production;

Hydropower Design Criteria, Hydropower waterways and plant designs, construction

cost estimates and economic analysis. Also included is a schematic presentation of

the proposed power evacuation.

(v) Volume 4 presents an album of Draft Engineering Drawings for the Omi Dam

Hydropower Project indicating the longitudinal profile of the penstock – powerhouse

route, powerhouse arrangement and turbine configuration.

(vi) Volume 5 contains the necessary Tender Documents, i.e. BEME, Specifications,

Instructions to Tender, Conditions of Contract) for the procurement of the

Construction of the Omi Hydropower Plant.

The aforementioned reports may be available with the respective federal government

departments or the Ministry of Power. We were able to source the following reports for our

analysis:

1. Volume 1: Project Manual, Site Assessment and Data Collection. (Vol-1)

2. Volume 3 (Part 1) – Feasibility Studies Report by Decrown Engineers Ltd. (Vol-3

Part-1)

3. Volume 3 (Part 2) – Preliminary Engineering Design Report (Vol-3 Part-2)

4. OMI HPP Design (Excel Workbook)

However, the following volumes were not available for reviewing:

- Volume 2: As-Built Drawings of Omi Dam.

- Volume 4: Omi Dam Hydropower Project – Preliminary Engineering Design Drawings

- Volume 5: Omi Dam Hydropower Project – Tender Documents

As per the technical studies made available, the following salient features of the dam can be

ascertained:

Salient Features of Omi Dam

Dam

Dam type - Homogeneous Zoned earth

Dam

Crest elevation - 247m

Length of crest - 1,976m

Maximum height above river bed - 43m

Crest width - 6m

Upstream slope - 2.5:1

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Downstream slope - 2.5:1

Upstream Protection - Dumped Rip-rap

Downstream Protection - Grass fill

Overflow Spillway

Length of spillway - 250m

Spillway crest level - 241.2 m

Maximum flow over spillway - 3,500m3/s

Bottom Outlet/Intake

Size of bottom outlet pipe - 3000mm

No. of bottom outlet pipe - 2

Shape of Pipe - Horse shoe

Size of intake pipe - N/A

No. of intake pipes - N/A

Size of irrigation pipe - N/A

No. of irrigation pipe - N/A

Size of ecological pipe - N/A

Types of pipes installed - Reinforced Concrete

Design Soil Parameters

Classification of soil of dam body/Fdn. - SC

Cohesion of the soil of dam body - 33KN/m2

Cohesion of foundation soil - 34KN/m2

Angle of internal friction of soil in dam - 500

Angle of internal friction (foundation soil) - 250

Coefficient of permeability of soil in dam - 2.7 – 8.61 x 10-7cm/s

Coefficient of permeability (foundation soil) - 6.7-15 x 10-9cm/s

Reservoir

Normal free board - 2.1m

Minimum free board - 1.0m

Normal water level (NWL) - 241m

Water stored at normal water level - 250x106m3

Maximum water level (MWL) - 244.9m

Water stored at maximum water level - 255x106m

3

Reservoir surface area at NWL - 25.7km2

Minimum water level - 226m

Dead storage - 57x106m3

Maximum reservoir emptying time - 70days

Water Demand

Domestic/Industrial Demand - 135,000m3/d

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Irrigation Water Demand - 951,000m3/d

Ecological Water Demand - 484,000m3/d

Hydrology of the Catchments Area

Catchments area - 1,642km2

Design flood inflow - 3,500m3/s

Design storm - 215mm

Water Treatment Plant - 60,000m3/day

Water Treatment Plant

A Regional Water Supply & Treatment Plant Project with treatment capacity of

60,000m3/day has been designed by Messrs John-Solomon & Partners (JPS) to be sourced

from the Omi Dam as far back as 2006 for the Lower Niger River Basin Development

Authority, Ilorin. About 30 rural communities and urban towns with populations ranging

from 5,000 to 10,000 persons with domestic water service level of 75 to 150 litres per day

would require about 45 million liters per day.

Irrigation Scheme

Originally, Omi Dam was a multipurpose dam proposed to impound the raw water of Oyi

River for water supply to selected rural and urban communities of Kogi State and for the

irrigation of some cultivable lands far away from the dam site. The towns and villages

expected to benefit from the project include Egbe, Oke Ere, Omi, Jege, Ejuku, Ejiba, Isanlu,

Mopa, Odokoro-Gbedde, Kabba, Oranre, Aginmi, Igbagun, Ekirin-Adde etc. to mention but a

few. The size of irrigable land originally conceived was for about 8,000 Ha for such crops as

rice, maize, wheat and vegetables.

Hydrological studies were also conducted as a part of the feasibility assessment done by

DeCrown. The hydrological studies were divided into the following parts:

- An Inflow study, which was handled and concluded in the Original Hydrological

Report by Progress Engineers Consultants and the New Hydrological Report further

conducted by Decrown Consultants. DeCrown appraised and updated the reports to

affirm whether the present reservoir capacity of Omi Dam can sustain the proposed

Hydropower Generation.

- A Water Demand Assessment Study, which defined and analyzed all the water uses,

abstractions and demands in the vicinity of the project area.

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- A Flood Study, which assessed the propensity of the Oyi River at different locations

of interest at the dam and hydropower plant outlet in particular.

- A Sedimentation Study, which involved field observation of the site and

identification of possible severe riparian erosion hazard or mass-wasting processes.

The purpose was to determine the main factors of influence, which are the sediment

load as it affects reservoir capacity and power generation; and grain shape/size as it

affects abrasion of hydraulic/power facilities and equipments.

All these studies are described in detail in the aforementioned reports submitted by

DeCrown Consultants. In conclusion, DeCrown states that “…a firm energy of about

1,600kWh for a 1.5MW power output (during both the dry and rainy seasons), peaking to

3,500kWh for a 2.5MW power output (during the rainy season only)” is possible at Omi dam.

The feasibility study also recommends “The need for the exploitation of Omi Dam

hydropower potential...“.

As part of our assessment, we have reviewed the existing feasibility studies & suggested

further steps/ studies to enhance the technical feasibility of the project. Our assessment are

shared in Appendix A2. Our technical team also conducted a site visit to the project and our

findings are shared in Appendix A3.

Recommendation & Conclusion based on our technical review

The Omi dam appeared to be sound structurally; nevertheless it called for better

maintenance of the various structures of the dam in general.

The dam was initially constructed to primarily cater to the irrigation demands for irrigating

8000 Ha of land. However it was noted that no substantial cultivation was being carried out

in the irrigated area. Also the discharge from the dam was not being controlled or

monitored. This clearly indicates that the waters stored in the Omi dam can be put to better

use such as that of power generation.

The following conclusions can be drawn:

1) The hydrology of the reservoir needs to be studied thoroughly using daily inflow data.

2) The need for the irrigation, domestic household purpose, ecological release, etc. need to

be ascertained before the firming up of the power potential is done.

3) Based on the assumptions made and the data shared in the reports, the dam can support

either hydro power plant or irrigation demand, domestic/industrial demmand and other

associated works. The elevation difference of ~16m between the irrigation canal and the

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tail water level of the proposed Hydro power project make the two schemes mutually

exclusive.

4) If hydro power plant is considered then based on the assumptions stated above the

optimum capacity will be of 2 MW with 48.55% plant load factor. The annual energy

generation is approximately 8.51 GWh with 4,687 hours of operation annually. However

a thorough study with detailed flow / discharge analysis needs to be conducted to firm

up these numbers.

5) A wing wall is recommended for safe guarding the powerhouse civil structures and E&M

equipment in case of flood. The elevation of the powerhouse elevation is ~218 m

whereas the Tail water level is 209 m. The highest flood discharge is 3550 cumecs. In

order to block this discharge of 3550 m3/sec, a suitably designed wing wall has been

proposed to be contructed. The reach of the flood discharge needs to be ascertained to

analyse the effectiveness of the wingwall.

11. Revenue forecasting for the proposed Omi Kampe Hydro power project

Revenue forecasting forms an important part of viability assessment for the project. The

power project revenues depend mainly on two factors:

a. The power generated and sold by the project and

b. The tariff for sale of power.

Thus, the revenue generated by the proposed hydro power project is a function of the ‘Net

energy sold’ and the ‘Electricity Tariff’.

I. Calculation of net energy sold

The Net Energy sold is calculated in the financial model as follows:

(a) Generation at 100% availability (in GWh) is calculated for a particular period is equally

to [ Plant Load Factor (PLF) X Installed capacity (in MW) X number of days X 24 (hrs.) /

1000]

(b) Generation at 100% availability obtained above is then multiplied by the “Annual

availability of plant” to get the “Generation at actual availability”. This calculation takes

into account the downtime of the plant and hence the loss of generation during such

downtime (whether planned or unplanned outage).

(c) “Auxiliary consumption” and “Transformation Losses” are subtracted from the

“Generation at actual availability” to obtain “Net Energy at Bus Bar”.

(d) The “Transmission losses to Interconnection point” are subtracted from the “Net

Energy at Bus Bar” to arrive at the “Energy at interconnection point”.

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(e) The “Free power” if any offered by the Private participant to the public participant

during the allotment process, is subtracted from the “Energy at interconnection point”

to arrive at the “Net energy sold”.

The Net energy sold multiplied by the tariff (Explained below under MYTO II calculation and

assumptions) gives the “Total regulated power revenue”. If any rebate is to be offered for

prompt payment by the electricity purchaser, this will be subtracted from the “Total

regulated power revenue” to arrive at “Total revenue from power sales”.

II. Tariff: Multi Year tariff Order II35

The Nigerian Electricity Regulatory Commission issued a multiyear tariff order in order to

provide a 15 year tariff plan for Nigerian Electricity Supply Industry. Minor reviews and

changes in the rate of inflation, foreign exchange rate are made annually. Major reviews and

changes are conducted every five years. The first set of tariffs under MYTO I were issued in

July 2008. MYTO II provides for the tariff determination from 1 June 2012 to 31 May 2017.

MYTO uses the ‘building block’ approach to determine the tariff. This helps it to incorporate

the positive attributes of both the rate of return mechanism and the price gaps mechanism

of tariff determination. The primary building block on which the MYTO has been built can be

summarized as below:

i. Allowed rate of return on the capital invested

ii. Distributing the capital invested over the useful life of the project (i.e. Depreciation)

iii. Efficient operating costs and overheads.

a. Treatment of Capital Cost in MYTO:

i. It is stated in the “MYTO Methodology” that “the initial value of the asset is

rolled forward each year. Depreciation reduces the valuation and new capital

increases it. Replacement cost, actual capacity ratings and remaining economic

life were taken into account in this valuation”.

ii. The cost of capital has been addressed in two notations:

In terms of depriciation

Return measured by the cost of capital

These values are calculated using the annual asset value, i.e. the rolled forward asset value.

b. Treatment of Depreciation in MYTO

The optimized depreciated replacement cost (ODRC) method has been used for the

calculation of tariffs in MYTO.

This involves the following:

35

Source: http://www.nercng.org/index.php/myto-2 Retrieved on 05 August 2013

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a. Adjusting the price of the asset from its year of purchase to the year of tariff

calculation.

b. Optimizing its capacity

c. Applying the depreciation over the economic life of the asset.

Different groups of assets will be subjected to different rates of depreciation.

c. Treatment of Cost of capital in MYTO

The cost of capital used in calculating the tariff order is estimated using the Weighted

Average Cost of Capital (WACC) method.

d. Treatment of Operational expenses in MYTO

The initial operating cost used (2000 – 2006) in the calculation have been obtained from the

Nigerian electricity industry. The O&M expenses are assumed to include an allowance to

improve the performance required under the performance indicators. It is stated that the

operation, maintenance and staff costs are expected to be higher in the initial years and

have been accounted for in the tariff calculation

The assumptions in the MYTO concerning the electricity industries’ ability to collect sales

revenue begin at current low levels but are assumed to improve over the first five years,

coinciding with an increase in metering roll-out and billing expenditure.

e. The major assumptions in the MYTO tariff calculation are as follows:

Inflation for Local Costs (CPI for Nigeria)

Inflation has been estimated till 2041 and values are input in the tariff model. Inflation is

used to adjust the variable operation and maintenance cost annually. It also used to adjust

the calculation of “Local cost Component” of the capital cost annually.

Change in Forex rate (US$ / NGN)

The exchange rate of US$/ NGN has been input as actual average annual values till 2011.

From year 2012 onwards, an annual depreciation of 5% has been assumed in the value of

the Naira.

Forex Under PPP (Purchasing Power Parity) Assumptions

In this row, the local inflation rate is adjusted with the US inflation.

US Inflation (CPI) per annum

The US inflation rate has been input as 2.5% p.a. till 2010 after which it is input as 3% p.a. till

the end. This is used in the calculation of the “US Components Split” in calculating the

capital cost used in the tariff calculation each year.

US CPI FX Adjusted Inflation per annum

As the name suggests, the US CPI inflation is adjusted for the “Naira Change”.

US CPI FX Adjusted

The indexed depreciation of the Naira using 2010 as the base year is calculated here.

Corporate Income Tax Rate (+ Education Tax)

This has been input at 32%.

Other Assumptions

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Particulars Units

Auxiliary requirements % 1.00%

Average Degradation % 2.00%

Capacity factor % 60.00%

Transmission Losses % of sent out 8.05%

Generation (MWh) 5,098.32

Equivalent capex payment per MW Naira/ MW 80,214.36

Equivalent tax payment per MW Naira/ MW 23,934.00

Capital cost (2011 Basis) US $/kW 3,500.00

US Components Split % 100%

Fixed O&M N/MW/year 5,655,000.00

Variable O&M (sent out) N/MWh 87.00

Generation

= 365 x 24 x [Capacity factor x (1- Average Degradation - Auxiliary requirements)]

= 365 X 24 X [60% X (1 - 2.0% -1.0%)]

= 5,098.32

III. Tariff Calculation

Tariff is calculated using the following formula:

Wholesale contract prices (N/MWh) = Fixed O&M (N/MWh) + Variable O&M (N/MWh) +

Capital cost (N/MWh) + Tax cost (N/MWh) +

Carbon Cost (N/MWh) + Transmission loss cost

(N/MWh)

These tariff components are calculated as follows:

a. Fixed O&M (N/MWh)

Formula:

= Fixed O&M / 365 / 24 / (Capacity factor X (1-Auxiliary requirements-Average Degradation))

b. Variable O&M (N/MWh)

Formula:

= [Variable Operation and Maintenance (sent out) assumed for base year (2011)] X (1+

Variable Operation and Maintenance escalation)

c. Capital cost (N/MWh)

Formula:

= [Equivalent Capex payment per MW (assumed for base year)] X 1000 / Generation (MWh)

d. Tax cost (N/MWh)

Formula:

= Equivalent tax payment per MW (assumed for base year) X 1000 / Generation (MWh)

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e. Carbon Cost (N/MWh)

Formula:

Assumed to be nil.

f. Transmission loss cost (N/MWh)

Formula:

= [Transmission Losses as a % of sent out] X Wholesale contract prices

The MYTO II tariff calculation has been replicated in the Financial Model in the ‘Tariff MYTO

II’ Sheet.

IV. The Clean Development Mechanism (CDM)36

In addition to the “Total revenue from power sales”, revenue is also generated from sales of

carbon credits earned by the project through CDM. The calculations for CDM revenues are

explained here. The Clean Development Mechanism (CDM) is a United Nations initiative

under the UNFCCC (United Nations Framework Convention on Climate Change) banner to

promote emission-reduction projects in developing countries that can earn certified

emission reduction (CER) credits. Each CER equates to one ton of CO2 abated. The CERs

generated can be traded / sold to the developed / industrialized nations to a meet a part of

their emission reduction targets under the Kyoto Protocol.

The revenue generated by the hydro power project through CDM is calculated as follows:

a. The “Energy at interconnection point” is multiplied with the “Grid intensity

factor for Nigerian Grid” to obtain the “Number of CERs generated”.

b. Next the Number of CERs generated is multiplied with the “Price per CER” to

obtain the “Revenue to IPP from CER sales”.

The “Revenue to IPP from CER sales” and “Total revenue from power sales” constitute the

“Total Revenue” for the project. Of the “Total Revenue” so calculated, 30% share is to be

provided to the “Hydroelectric Power Producing Areas Development Commission” as per

the existing law. “Total Revenue” less the “Revenue shared With Hydroelectric Power

Producing Areas Development Commission” thus gives us the “Net Revenue” for the

project.

The revenues from the sale of CER will be an additional source of revenue from the project.

On analyzing the financial results without the revenues from CER sales, the following results

were obtained:

Particulars Unit Returns with CDM

Benefits

Returns without

CDM Benefits

Project IRR % 19.40% 19.25%

36

Source: http://cdm.unfccc.int/about/index.html Retrieved on 05 August 2013

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Particulars Unit Returns with CDM

Benefits

Returns without

CDM Benefits

Private Participant Returns

IRR % 24.42% 24.15%

Payback period years 7 7

NPV MM USD 0.87 0.84

Public participant Returns

NPV of Dividends received MM USD 0.12 0.12

NPV of Total Revenue MM USD 0.22 0.22

Debt Service Coverage Ratio

Average DSCR 2.32x 2.29x

Minimum DSCR 1.82x 1.81x

We would like to note here that the CDM revenues are just about 1% of the total revenues

of the project. The majority of the revenues are coming from sale of electricity. Therefore,

the sensitivity of the financial results to the CDM revenues is expected to be very low. Even

without the CER sales revenue, the financial results are equally encouraging.

V. Revenue sharing and project ownership

The Hydro power project will be allotted to the private participant on the basis of an

International competitive bidding (ICB) based on one or more of the following parameters:

a. Up front premium to the public participant

b. Free power to the public participant

c. Free Equity to the public participant

The Public participant may, at its own option, invest funds at par for an equity share in the

project. In such a case, the public participant will be allotted equity shares proportional to

the investment made. Thus, project ownership of the Public participant will consist of (a)

Free Equity (if any) & (b) Equity allotted to Public Participant at Par investment (in case the

Public participant exercises the option of investment).

In the financial model for the base case, we have assumed that the Public participant will

NOT invest any money in the project as equity investment. The public participant

investment in the project thus has been assumed to be NIL. The total equity investment

required for the project is estimated at US$ 1.18 million and is fully invested by the Private

Participant.

i. Equity ownership of Public Participant

EPB = Free equity + Equity share for par investment

Free equity has been currently assumed to be 5% in the Financial Model. The equity share

for par investment can be worked out as:

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= [(Equity invested by Public Participant at Par investment) / (Total Equity investment)] X [1 -

Free Equity to Public participant]

= (0.0 / 1.18) / (1 – 5%)

= 0.00%

Thus total equity ownership of Public Participant in project is:

EPB = 5% + 0.00% = 5.00%

In case the Public Participant exercises its option of investment in the project, the total

equity ownership of the Public Participant will be calculated as per the above formula.

ii. Equity ownership of Private Participant

EPP =1 – EPB

= 1– 5.00%

= 95.00 %

Project Ownership Percentage

Private Participant

95.00%

Public Participant

5.00%

O/W Equity to Public Participant at Par investment 0.00%

O/W Free Equity for Public Participant

5.00%

Total

100.00%

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12. Project Cost estimate

It is estimated that the project will cost approximately US$ 3.95 million. The table below

summarizes the total project cost.

Sr. No. Cost Components US$ Million

1 Civil Works 1.39

2 E & M 1.72

Out of which: Transmission Work 0.53

Total cost without IDC & FC 3.11

3 Indirect Cost 0.03

(a) Total direct & indirect cost 3.14

4 Initial Working capital, capitalized spares 0.05

5 Interest during Construction, Financial Charges 0.26

6 Escalation during construction 0.24

7 Contingency 0.16

8 DSRA Cost loaded upfront 0.11

(b) Total other cost 0.81

9 Total (a) + Total (b) 3.95

10 Capacity in MW 2

11 Cost per MW 1.97

12 Total project cost 3.95

The chart below gives a graphical view of the breakup of the capital cost:

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Chart. 8: Breakup of the capital cost

The detailed break up and explanation of cost of the various components of the project are

shared in Appendix A4.

13. Financial Model

The Excel spreadsheet named ‘OMI HEP FM - Nigeria - SCG 02082013.xlsm’ is a spreadsheet

based Financial Model (the “Model” or “FM”) for the proposed OMI Kampe Hydro Electric

Power Project in the Kogi state of Nigeria (the “Project”). The FM provides financial

projections for an assumed operation period of 30 years from the date of commissioning of

the Project. The starting date for the FM is January 01, 2014, and the ending date is 31st

December 2046. The operation period is from January 01, 2017.

The Model replicates the financial implications of project finance, construction and

operation under a PPP mode. The FM contains projected financial statements and calculates

the Internal Rate of Return (IRR) for the Private Participant and the Net Present Value of the

potential cash flows to the Public Participant.

The model calculations are divided into two main parts: the construction & development

periods which are modeled on monthly bases and the operations period which is modeled

on a quarterly basis. The model phases the development expenditure over a period of 12

months and the construction expenditure over a period of 24 months.

Civil Works

35%

E & M

43%

Indirect Cost

1%

Initial Working capital,

capitalized spares

1%

Interest during

Construction, Financial

Charges

7%

Escalation during

construction

6%

Contingency

4%

DSRA Cost loaded

upfront

3%

Break Up of Project Capital Cost

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Chart. 9: Construction and development expenditure over a period of 36 months

The development expenditure is fully funded through equity. The equity funds are invested

by the public & private participants in proportion to their ownership.

Debt is included as a source of funds in the debt: equity ratio (70:30) and Debt drawdown is

permitted during the construction period after the financial closure.

3%3%

4%4%

5%

5%

6%6%

12%13%

14%

15%

22%26%

29%33%

37%41%

43% 46%

50% 52%

54% 58%

61% 65%

70%71%

73%75%

76% 79%

81%

88%

93%

100%

0%

20%

40%

60%

80%

100%

120%

-

0.05

0.10

0.15

0.20

0.25

0.30

0.35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

MM

US

D

Months

Cumulative Construction Cost

Construction

Budget

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Chart. 10: Source of funds during construction

The model covers an operation period of 30 years, calculating the electricity generation and

revenue realization for the project. It accounts for the operations and maintenance (O&M)

cost, interest and principal payment & tax payments to generate financial statements such

as P&L Account, Cash Flow and Balance Sheets. Other calculations such as depreciation and

amortization, working capital are also included for each quarter.

The financial returns to the private & public participants are calculated in separate sheets in

the financial model. The Debt Service Coverage Ratio is also calculated in the “DSCR” sheet.

The model identifies the critical variables that have a significant impact on the results of the

model. The model conducts Sensitivity Analysis for these variables for a range of values and

calculates their impact on financial indicators such as investor returns. The summary of

results of the sensitivity analysis is shared in the “Sens.” Sheet.

The model operating procedure, the assumptions and the results of the financial model

have been discussed below:

13.1 Financial Model: General

The Model is a Microsoft Excel Version 2010 file consisting of 23 worksheets. The Model

contains one macro, in the ‘Sens.’ worksheet. Please see ‘Macros’ section in this document

for more details.

-

0.50

1.00

1.50

2.00

2.50

3.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

MM

USD

Months

Equity Senior Debt

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The model is based on the standard distinction between hard-coded inputs (in blue ink and

yellow background) and calculated values (in black ink and white background). Although the

‘Assumption’ worksheet contains a number of calculations, most of the hard coded inputs

are contained in this Input worksheet. There are very few hard coded values used in the

other Calculation or Output sheets.

13.2 Financial Model: Set up

The model covers two distinct periods: a construction period modeled on monthly basis in

the ‘Capex’ sheet, and an operating period, modeled on a quarterly basis. The construction

period covers three years from CY 2014 through CY 2016, while the operating period covers

30 years from CY 2017 through CY 2046.

The Financial Model uses special date functions that require Excel Add-ins to be enabled.

This can be enabled in the following manner.

If using Excel 2003 or earlier version of MSExcel: Please go to the 'Tools' button in the menu

bar, select 'Add-ins' and select the boxes labeled ‘Analysis Toolpak' and ‘Analysis Toolpak –

VBA.’

If using Excel 2007: Please click on circular office button at top left corner, click on ‘Excel

Options’ at the bottom, Click on ‘Add Ins’ and Click on ‘Go’. Select the boxes labeled

‘Analysis Toolpak' and ‘Analysis Toolpak – VBA.’

If using Excel 2010: Please click the ‘File’ Button and then click on ‘Options’. In the pop-out

box on the left hand side column, please select ‘Add-Ins’. In the drop down menu at the

bottom of the page next to ‘Manage:’ choose ‘Excel Add-ins’ and click on ‘Go’. Select the

boxes labeled ‘Analysis Toolpak' and ‘Analysis Toolpak – VBA.’ Click on ‘Ok’.

13.3 Financial model: Structure

The financial model is comprised of 23 worksheets, briefly described below.

Worksheet Description

Index Introduces the sheets and states the color conventions used in

the model

Cover Introduces the Client, Model Version and the Disclaimer

Check Summarizes all the checks in the model for arithmetic and

posting accuracy

Sens. Displays the sensitivities of financial results vis-à-vis changes in

inputs

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Worksheet Description

Summary Presents the summary of the Power Generation, Commercial and

financial calculations. Calculates the Levelized cost of generation

Assumptions Contains most of the model inputs

Project cost input Inputs for project cost are contained in this sheet

Capital cost Summarizes the total capital cost of the project (Hard cost +

Financial Cost + Contingencies)

Capex Contains the Drawdown schedule of the project development

and construction period; provides calculation of IDC, financing

costs

Gen. Calculates the generation of power based on installed capacity,

PLF, and losses

Debt Calculates the principal and interest repayment of the Senior

Debt

Tariff MYTO II Calculates the tariff for the respective year based on the MYTO II

Guidelines

O&M costs Calculates the Operation and Maintenance cost per quarter

Rev. Calculates the revenue generated by sale of Power and sale of

CERs

Working capital Calculates the working capital requirement for the plant

operations

Depr. & tax Calculates the Depreciation and Tax payments

Financial stat. Calculates and Displays the Financial Statements: Profit & loss

Account, Cash Flow Statement and Balance sheet

DSCR Calculates and displays the Debt Service Coverage Ratio for the

Senior Debt

Private participant IRR Calculates the IRR for the investment made by the Private

participant

Public participant IRR Calculates the IRR for the investment made by the Public

participant

Public participant return Calculates the returns to the Public Participant based on Free

Equity, Equity issued at Par and upfront premium

Graphs Displays the graphical interpretation of the Cash flow waterfall,

expenditure during construction and the Debt service coverage

ratio

Dev cost Input for the various expenditures incurred during the project

development period

Note – The above may not be in the same sequence as in the model.

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13.4 Financial model: Macros

The Model contains the following Macro:

Macro Name Objective

Sensitivity To run the sensitivity cases listed in rows 23-41 in ‘Sens.’ Sheet

For the model to function correctly, the Macros need to be enabled from the security or

macro settings toolbar.

13.5 Financial model: Checks

A number of checks have been incorporated in the financial model. The outcome of such

checks is reported in the sheet “Check”, which then returns an overall status check for the

model: “TRUE” if no errors are reported or (Number of errors) “Error(s)” if one or more

errors are reported. The base case should always report a “TRUE” status.

The various assumptions used in the financial model have been shared in Appendix A5.

13.6 Financial Model: Base case results

The base case results show that the project will cost US$ 3.95 MM and will be financed with

an equity investment of US$ 1.18 MM and senior debt of US$ 2.77 MM. It is estimated that

the project will be generate 8.49 GWh of electricity per annum at a levelized generation cost

of 10.21 US c/KWh.

The net revenue from electricity sales has been calculated to be around US$ 1.00 MM in the

first year. This is after accounting for the “Revenue shared With Hydroelectric Power

Producing Areas Development Commission” at 30%. The project is expected to have an

EBITDA of 94% and a PAT of 46%.

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Chart. 11: Cash Flow over a period of 30 Years of operation

Chart. 12: Debt Service coverage ratio

The revenues from the project will support an average DSCR of 2.32x and a minimum DSCR

of 1.82x which is in the acceptable range. The project IRR is expected to be around 19%,

whereas the private participant equity IRR would be around 24.42% in the base case.

-

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

MM

US

D

Years

Cash flow chart

Revenues EBIDTA Cash for debt service Total Senior Debt service Dividends

0.00x

1.00x

2.00x

3.00x

4.00x

5.00x

6.00x

1 2 3 4 5 6 7 8 9 10Years

DSCR (Senior Debt)

DSCR (Senior Debt)

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The payback time for the equity investment is expected to be seven (7) years from the start

of project development activities. The Net Present Value (NPV) of the private sector equity

investment over a period of 33 years is calculated to be US$ 869,747. Thus, in the base case,

the project shows promising returns to the private sector participant.

The returns for the public participant are encouraging too. The NPV of the future cash flows

from the project to the Public Participant is around US$ 223,029.

Chart. 13: Cumulative Cash flow to Project stake holders since start of construction

The results of the financial model have been shared in Appendix A6. All tables other than

the sensitivity analysis are for the ‘Base Case’ model run:

Table 1.1 – 1.2 : Sensitivity analysis

Table 2.1- 2.3: Balance Sheet

Table 3.1 – 3.3: Profit and Loss Account

Table 4.1 – 4.3: Cash flow statement

Table 5.0: Private participant IRR

Table 6.0: Project IRR

Table 7.1 - 7.4: Returns to Public Participant

Table 8.0: Levelized cost of generation

Table 9.0: Debt Service Coverage Ratio

(0.80)

(0.30)

0.20

0.70

1.20

1.70

2.20

2.70

3.20

3.70

4.20

(5.00)

-

5.00

10.00

15.00

20.00

25.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

Cu

mu

lati

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icip

an

t (M

M U

SD)

Cu

mu

lati

ve C

ash

flo

w f

or P

riva

te E

qu

ity

(MM

USD

)

Months

Cumalative Cashflow for Private Paticipant

Cumalative Cashflow for Public Paticipant (RHS)

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13.7 Financial model: Sensitivity Analysis

The ‘Sens.’ sheet lists down different sensitivity cases (rows 23-41) based on variation in

values of critical input variables. For e.g. Sensitivity no 2 in row 25 is labeled as ‘Case 2 -

Increase in Capital Cost by 10 %’. The corresponding cell to be changed for this sensitivity is

cell D25 which has 10% as its value currently. This means that this case will show the effects

of a 10% increase in Capital Cost. The value in cell D25 can be changed so as to see the

impact of the required % increase in capital cost. The ‘Sensitivity’ macro is run using the

‘Run Sensitivity Analysis’ button on the sheet. The output for this sensitivity case can be

seen in cells from row 46 onward of the same sheet. The following list gives the case no and

the sensitivities that can be run in those cases.

Table 1.1 Sensitivity analysis case description

Sr. No Case & Description

0 Base Case - No Change

1 Case 1 - Increase in Capital Cost by 5 %

2 Case 2 - Increase in Capital Cost by 10 %

3 Case 3 - Decrease in Annual Plant Availability by 5 percentage points

4 Case 4 - Decrease in Annual Plant Availability by 8 percentage points

5 Case 5 - Increase in Base operating cost by 5 %

6 Case 6 - Increase in Base operating cost by 10 %

7 Case 7 - Lower Hydrology by 5 %

8 Case 8 - Lower Hydrology by 10 %

9 Case 9 - Bad year every five years (10 % less water)

10 Case 10 - Higher inflation by 5 % points

11 Case 11 - [Spare]

12 Case 12 - Lower number of carbon credits by 20 %

13 Case 13 - Lower price for carbon credits by 20 %

14 Case 14 - Increase in construction period by 12 months

15 Case 15 – [Spare]

16 Case 16 - Combined downside Case A

17 Case 17 - Combined downside Case B

18 Case 18 - Combined downside Case C

13.8 Financial model: Inferences from sensitivity analysis

The sensitivity analysis shows that the deviations in the cost of the project and the returns

to investors are with a permissible range. The project has the cushion to absorb the changes

in cost, construction period, changes in hydrology, etc. It is observed that the even when the

cost of the project increases by 10%, the minimum DSCR is at 1.62x and the average DSCR is

at 2.32x. The Internal rate of return to the private participant falls to 21.97% and NPV of

future cash flows to the public participant is 0.22 MM USD.

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A decrease in hydrology by 10% results in a minimum DSCR of 1.49x and average DSCR of

2.12x. The Internal rate of return to the private participant falls to 21.89% from 24.42% in

the base case and NPV of future cash flows to the public participant falls to 0.20 MM USD

from 0.22 MM USD in the base case. It is observed that the target DSCR is not breached in

any of the assumed cases. The chart below summarizes the results obtained for the debt

service coverage ratio in various cases:

Chart. 14: Debt Service Coverage Ratio variation in sensitivity analysis.

It is also observed that the levelized cost of generation ranges between 10.21 US c/KWh and

11.20 US c/KWh. Both the numbers are below the levelized tariff of 19.04 US c/KWh defined

under the MYTO II guidelines.

The sensitivity analysis checks for three cases of variation in capital cost: the base case, an

increase of 5% in capital cost and an increase in 10% in capital cost. The results are

satisfactory in all the three cases. While the equity employed increases from 1.18 MM USD

in the base case to 1.35 MM USD with an increase of 5% in capital cost and to 1.53 MM USD

with an increase in 10% in capital cost, the levelized cost of generation remains well below

the Levelized tariff of 19.04 US c/ KWh. The graphical representation of the same is shown

in the chart below:

1.15 x

1.30 x

1.45 x

1.60 x

1.75 x

1.90 x

2.05 x

2.20 x

2.35 x

2.50 x

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

DSC

R

Case Number

Debt Service Coverage Ratio

Min. DSCR Senior Debt Avg. DSCR Senior Debt Target DSCR

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Chart. 15: Impact of increase in Project cost on Levelized cost of Generation

The sensitivity analysis also checks for five cases of variation in generation based on

variation in plant availability and hydrology including the base case. The results show that

even at the minimum generation of 7.61 GWh (for 10% lower hydrology), there is still a

difference of 8.61 US c / KWh between the levelized generation cost and the levelized tariff

under MYTO II. The chart below shows the results of this comparison.

1.18 1.35 1.53

2.8 2.8 2.8

-

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

-

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Base case 5% Inc. in cost 10% Inc. in cost

US

c/K

Wh

MM

USD

Total Debt (LHS) Total Equity (LHS)

Levelized cost, US c/KWh (RHS) Levelized Tariff, US c/KWh (RHS)

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Chart. 16: Effect on generation and levelized cost

Three of the cases checked for in the sensitivity case runs are a combination of various

factors, as described below:

Case 16 - Combined downside Case A

Sensitivity Criteria Parameters impacted by sensitivity criteria

Increase in operational expenses by

5% Cash available for debt service and dividends

Power potential lower by 5% Decrease in power generation, negative impact on all

investor return parameters

Construction time overrun by 12

months

Increase in the cost of the project, negative impact on

investor returns

Case 17 - Combined downside Case B


Increase in capital cost by 5% Increase in the cost of the project, negative impact of

returns

Power potential lower by 10% Decrease in power generation, negative impact on all


-

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

7.00

7.20

7.40

7.60

7.80

8.00

8.20

8.40

8.60

Base Case Dec. in Plant

Availability by 5%

Dec. in Plant

Availability by 8%

Lower hydrology

(5%)

Lower hydrology

(10%)

US

c/K

Wh

GW

h

Generation, GWh Levelized cost, US c/KWh Levelized Tariff, US c/KWh (RHS)

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Case 18 - Combined downside Case C


Decrease in annual plant availability

by 5%

Decrease in power generation, negative impact on all


Construction time overrun by 12

months

Increase in the cost of the project, negative impact on

investor returns

Chart. 17: Combined downside cases of sensitivity analysis

The table below shows a comparison of the results obtained in the combined downside

cases in the sensitivity analysis in comparison with the base case results. It can be seen in

that even in even the combined downside case B, the results are within the acceptable

range. Thus, the project has the cushion to absorb the negative impacts of certain critical

input variables such as capital cost.

-

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

7.00

7.20

7.40

7.60

7.80

8.00

8.20

8.40

8.60

Base Case Case A Case B Case C

US

c/K

Wh

GW

h

Generation, GWh Levelized cost, US c/KWh (RHS) Levelized Tariff, US c/KWh (RHS)

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Case Run

Project

Cost

Million

USD

Equity

Million

USD

Generation

GWh

Levelized

cost, US

c/KWh

Min.

DSCR

Debt

Avg.

DSCR

Debt

IRR Private

Participant

NPV Public

Participant

Million USD

Base Case 3.95 1.18 8.46 10.21 1.62 x 2.33 x 24.4% 0.22

Combined

downside

Case A

3.95 1.18 8.03 10.51 1.55 x 2.22 x 23.1% 0.21

Combined

downside

Case B

4.14 1.35 7.61 11.20 1.49 x 2.11 x 20.7% 0.20

Combined

downside

Case C

3.95 1.18 8.00 10.51 1.55 x 2.21 x 23.1% 0.21

The graph below displays the variation in IRR for the private participant and the public

participant.

Chart. 18: Internal Rate of Return for the public participant and the private participant

13.9 Analysis of suggested bidding parameters for hydro power projects

Bidding and allotment of hydro power projects is a detailed & complicated transaction and

substantial work is required in the preparatory stage of the project (Pre-Bid). After the type

0.20

0.20

0.21

0.21

0.22

0.22

0.23

0.23

17.00%

18.00%

19.00%

20.00%

21.00%

22.00%

23.00%

24.00%

25.00%

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

MM

US

D

IRR

in

%

Sensitivity Case number

IRR Private Participant (LHS) NPV Public Participant Million USD (RHS)

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of PPP arrangement is finalized (see Appendix 7 and Appendix 8), one of the critical

decisions to be made by the authorities is the selection of an appropriate bidding parameter

(the parameter based on which project is to be allotted). Across the world, the following

generally accepted bidding parameters are used for allotment of hydro power projects:

Highest Free power

Highest Free equity

Highest Upfront premium


Highest lease or rent payment for facility (lease payment may be fixed or

variable)

Lowest tariff for electricity (if tariff is not fixed by regulator or if discount to

tariff is used as a measure for evaluating bids)

Lowest cost of project (if the project ownership is to be with public

participant & the investment is being financed by the public participant)

Or a combination of two or more parameters (by keeping only one variable

parameter and fixing the value of all others).

Selection of an appropriate bidding parameter depends on, among other things, project

features such as cost, ease of execution, financial status of public participant, stage of

project (operational or under development). Other factors affecting the bidding parameter

selection are local conditions, financial position or strength of host country, investment

sentiment, maturity of financial markets and private sector interest levels.

The following sections describe in detail the impact of selection of different bidding

parameters on the financial indicators of the project.

13.9.1 Free power

As the name suggests, ‘Free Power’ refers to a certain percentage or a fixed quantum of

electricity provided free of cost to the public participant from the total electricity generated

by the project. It may be calculated as a percentage of the “Energy available at the

interconnection point”, net of losses and adjustments for plant availability, auxiliary

consumption, and transmission & other losses.

13.9.1.1 Mechanism of bids based on free power

The public participant may set a base or a minimum value for the free power bid and the

bidders are required to provide an additional free power number over and above the base

value. Since the debt and interest expenses would be higher in the initial years, the

concession period may be divided into two or three periods or tranches and the base value

of free power may be set to increase from one period to the next. The first tranche covers

the loan or project finance amortization period. The base value for the first tranche should

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be kept at a lower level to enable the financial viability of the project in the early years. The

base free power may increase progressively (or in steps) over the remaining life of the

project.

13.9.1.2 Key benefits for the Public participant

A bid based on free power ensures a steady flow of free electricity to the public participants

throughout the concession period. This helps in lowering the electricity procurement price

for the government and may also help in fulfilling social obligations of the government,

especially in the project vicinity.

13.9.1.3 Key benefits for the Private participant

A free power based bid has a number of benefits for the private participant. These include:

Reduction in the initial expense burden for the developer as compared to an

upfront premium based bid

Phased cash outflow to the public participant over the entire concession period

Payment (in kind) to the Public participant through electricity generated; No fixed

or upfront obligation on the Private Participant

13.9.1.4 Demerits of a free power based bid

The principal demerit of a free power based bid is that any income to the public participant

is contingent on completion of the project. Secondly, as there is no upfront or fixed

payment obligation on the private participant, the bid may have participation from non-

serious or financially weak bidders. The bid qualification requirements should be such that

only qualified and financially sound bidders are allowed to participate in the bid process.

13.9.1.5 Financial analysis of a free power based bid for Omi Kampe dam

Base case assumptions:

Minimum free power: Nil

Base Free Equity: 5.0%

Upfront Premium: US $ 50,000

Bidding Parameter tested: Free power

In order to test the effect of variation of free power value over the financial results, we have

kept the other three parameters constant and varied the free power value from 0% to 18%,

with increments of 1% in each case. Thus, 19 cases with varying value of free power

component were run in the financial model and the following results were obtained:

Table: 1 Financial Results after testing for variation in free power

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Case

number:

Bidding

Parameter:

Free Power

Min. DSCR

Senior Debt

Avg. DSCR

Senior Debt

IRR Private

Participant

NPV Public

Participant

Million USD

Case No. 1 0.0% 1.83 x 2.32 x 24.38% 0.22

Case No. 2 1.0% 1.81 x 2.30 x 24.13% 0.30

Case No. 3 2.0% 1.80 x 2.28 x 23.88% 0.38

Case No. 4 3.0% 1.78 x 2.26 x 23.62% 0.45

Case No. 5 4.0% 1.77 x 2.24 x 23.37% 0.53

Case No. 6 5.0% 1.75 x 2.22 x 23.12% 0.60

Case No. 7 6.0% 1.74 x 2.19 x 22.86% 0.68

Case No. 8 7.0% 1.72 x 2.17 x 22.61% 0.76

Case No. 9 8.0% 1.71 x 2.15 x 22.35% 0.83

Case No. 10 9.0% 1.69 x 2.13 x 22.10% 0.91

Case No. 11 10.0% 1.68 x 2.11 x 21.84% 0.98

Case No. 12 11.0% 1.66 x 2.09 x 21.58% 1.06

Case No. 13 12.0% 1.65 x 2.07 x 21.32% 1.14

Case No. 14 13.0% 1.63 x 2.05 x 21.07% 1.21

Case No. 15 14.0% 1.62 x 2.03 x 20.80% 1.29

Case No. 16 15.0% 1.61 x 2.00 x 20.54% 1.36

Case No. 17 16.0% 1.59 x 1.98 x 20.28% 1.44

Case No. 18 17.0% 1.58 x 1.96 x 20.02% 1.51

Case No. 19 18.0% 1.56 x 1.94 x 19.77% 1.59

As expected, the internal rate of return (IRR) for the private participant decreases and the

Net present value of the returns for the Public Participant increases with an increase in the

free power component.

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Chart: 4 Impact of variation of Free Power on IRR (Private Participant) and the Net

present Value (Public Participant)

The Debt service coverage ratio also decreases with an increase in the free power

component. However, the DSCR values are at acceptable levels even with the free power

component value at 18%.

Chart: 5 Impact of variation of Free Power on the Debt Service Coverage Ratio

(DSCR)

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0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10% 11% 12% 13% 14% 15% 16% 17% 18%

NPV

Mil

lio

n US

D

IRR

(%

)

Free Power

IRR Private Participant NPV Public Participant Million USD

1.00 x

1.15 x

1.30 x

1.45 x

1.60 x

1.75 x

1.90 x

2.05 x

2.20 x

2.35 x

2.50 x

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10% 11% 12% 13% 14% 15% 16% 17% 18%

DS

CR

Free Power

Min. DSCR Senior Debt Avg. DSCR Senior Debt Target DSCR Senior Debt

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With free power being the only variable bidding parameter, it is observed that results in

‘case 8’ i.e. 11.0% free power results in in the IRR for the private participant to be above

21%, the NPV for the public participant to be above 1 million USD and the average DSCR at

2.09x. These are acceptable levels of financial indicators for both the public and private

participant. Thus, it may seem that the free power component (if selected as the bidding

parameter) may settle in the range of 10-12% for this project. The actual numbers may be

different, as it is a competitive bid and various factors affect the outcome of the bid.

13.9.2 Free equity as bidding parameter

Free equity is the equity ownership in the project company and thus in the hydro project,

awarded to the Public participant without the public participant investing capital in the

project. Thus, the private participant invests 100% of the required equity capital in the

project, but receives an ownership interest in the project which is less than 100%. Public

participants may set a base or minimum free equity value in ‘Free Equity’ based bids. Unlike

the free power bid, the free equity value generally remains constant and does not increase

with time.

The Public participant may retain an option to invest capital for further equity interest in the

project (an ‘at par’ investment, called ‘paid equity’) after the commissioning of the project.

This helps them gain control of the project & its operations during the concession period.

13.9.2.1 Key benefits for the Public participant:

A free equity based bid provides the public participants with a steady source of dividend

income all through the concession period. It also gives the public participant greater access

into the functioning of the project company through the board of directors. As a

shareholder, the Public Participants get the right to access documents pertaining to the

project company, which may otherwise be unavailable to it.

13.9.2.2 Key benefits for the Private participant:

Like ‘Free Power’, free equity also spreads the payment to the Public Participant over the

life of the concession agreement. The other key benefits to the Private participant in a free

equity based bid, is that greater help and involvement from the government can be

expected in obtaining the various clearances from government authorities or departments.

13.9.2.3 Demerits of a free equity based bid:

All cash flows to the public participant are contingent to the commissioning of the project.

Being shareholders, the public participants may be seen as interfering in the functioning of

the project company. This might be a deterrent to the prospective private participants in the

bid.

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13.9.2.4 Financial analysis of a Free Equity based bid for Omi Kampe dam


Free Power: Nil

Free Equity: Varying from case to case


Concession Period: 30 Years

Bidding Parameter tested: Free Equity

In order to test the effect of variation of free equity value over the financial results, we have

kept the other parameters constant and varied the free equity value from 5% to 31.5%, with

increments of 1.5% in each case. Thus, 19 cases with varying value of free equity component

were run in the financial model and the following results were obtained:

Table: 2 Financial Results after testing for variation in Free Equity

Sr. No. Free Equity IRR Private

Participant

NPV Public

Participant Million

USD

Case No. 1 5.00% 24.38% 0.22

Case No. 2 6.00% 24.21% 0.25

Case No. 3 7.50% 23.96% 0.29

Case No. 4 9.00% 23.71% 0.32

Case No. 5 10.50% 23.46% 0.36

Case No. 6 12.00% 23.21% 0.40

Case No. 7 13.50% 22.95% 0.43

Case No. 8 15.00% 22.69% 0.47

Case No. 9 16.50% 22.44% 0.51

Case No. 10 18.00% 22.18% 0.54

Case No. 11 19.50% 21.91% 0.58

Case No. 12 21.00% 21.65% 0.62

Case No. 13 22.50% 21.38% 0.65

Case No. 14 24.00% 21.11% 0.69

Case No. 15 25.50% 20.84% 0.73

Case No. 16 27.00% 20.57% 0.76

Case No. 17 28.50% 20.30% 0.80

Case No. 18 30.00% 20.02% 0.84

Case No. 19 31.50% 19.74% 0.87

It is observed that even at a level of 30% free equity, the IRR for the private participant is at

20% levels and the NPV for the Public Participant is around 0.84 Million USD.

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Chart: 6 Impact of variation on free equity on IRR (Private Participant) and the Net

present Value (Public Participant)

Any change in free equity has no impact on the debt service coverage ratio or the levelized

cost of generation. The returns to the Public Participants based on the free power obtained

have been calculated using the MYTO II tariff. As the sale of power by the public participant

/ Government to the end consumer is expected to be above this rate, there exists a

potential upside for the public participant, depending on the final price of sale of power.

Based on the above assumptions, free equity in the range of 20% may be obtained by the

public participant if the bid is conducted based on this parameter.

13.9.3 Upfront premium as bidding parameter

As the name suggests, upfront premium is a payment made by the successful bidder to the

government as soon as the project is awarded to the bidder. The Public participant may set

a base or a minimum upfront premium value and the bidders may be required to bid above

that. It is a common practice for the bidders’ security / Earnest money deposited at the

beginning of the bid to be adjusted against the net upfront premium payable. Upfront

premium is generally bid on a per MW basis and calculated for the project based on its

proposed installed capacity.

13.9.3.1 Key benefits for the Public participant:

An upfront premium based bid ensures that only serious bidders / developers bid for the

project as there is a major upfront expense involved. A bid of this nature also promises the

public participants’ cashflows right in the beginning of the project contrary to the free

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0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

NPV

Mil

lio

n US

D

IRR

(%

)

Free EquityIRR Private Participant NPV Public Participant Million USD

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power and free equity based bids. Also, the public participant’s cash flow is not dependent

on the execution and completion of the project.

13.9.3.2 Key benefits for the Private Participant:

An upfront premium based bid results in substantial cash outflows right in the beginning of

the project lifecycle. This helps ward of competition and helps cash rich entities get an

advantageous position in projects. Secondly, since there is no recurring long term benefit

sharing, the private participant corners all potential benefits of efficient project execution

and operation.

13.9.3.3 Demerits of an upfront premium based bid:

The principle demerit of an upfront premium based bid is that it may reduce competition as

some bidders may be discouraged by the substantial upfront expense. Secondly, the public

participant gives away all potential future benefits (windfall gains) from the operation of the

project. This also leads to the interest of the public participant in the Project to dwindle as

time progresses.

13.9.3.4 Financial analysis of a Upfront Premium based bid for Omi Kampe project


Free Power: Nil

Free Equity: 5.0%

Minimum Base Upfront Premium: US $ 50,000 per MW

Concession Period: 30 Years

Bidding Parameter tested: Upfront Premium

In an upfront premium based bid all risks pertaining to the development, implementation,

execution and development of the project are alienated from the public participant.

Accounting for the base assumptions stated above and testing for a various levels of upfront

premium the following noteworthy results were obtained:

Table: 3 Financial Results after testing for variation in Upfront Premium

Case. No. Upfront

Premium

USD / MW

Project

cost

Million

USD

Levelized

cost, US

c/KWh

IRR Private

Participant

NPV Public

Participant

Million

USD

Case 1 50,000 3.95 10.28 24.38% 0.22

Case 2 65,000 3.99 10.33 24.10% 0.25

Case 3 80,000 4.02 10.41 23.78% 0.28

Case 4 95,000 4.06 10.48 23.47% 0.31

Case 5 110,000 4.09 10.56 23.17% 0.34

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Case. No. Upfront

Premium

USD / MW

Project

cost

Million

USD

Levelized

cost, US

c/KWh

IRR Private

Participant

NPV Public

Participant

Million

USD

Case 6 125,000 4.13 10.63 22.87% 0.37

Case 7 140,000 4.17 10.71 22.59% 0.40

Case 8 155,000 4.20 10.78 22.31% 0.43

Case 9 170,000 4.24 10.84 22.08% 0.46

Case 10 185,000 4.28 10.91 21.82% 0.49

Case 11 200,000 4.31 10.99 21.56% 0.52

Case 12 215,000 4.35 11.06 21.30% 0.55

Case 13 230,000 4.38 11.14 21.05% 0.58

Case 14 245,000 4.42 11.21 20.81% 0.61

Case 15 260,000 4.46 11.26 20.55% 0.64

Case 16 275,000 4.49 11.34 20.10% 0.67

Case 17 290,000 4.53 11.41 19.66% 0.70

Case 18 305,000 4.57 11.49 19.25% 0.73

Case 19 320,000 4.60 11.56 18.85% 0.76

In the base case an upfront premium of US$ 50,000 is assumed and the value is increased by

US$ 15,000 in each of the subsequent cases.

The increase in upfront premium increases the cost of the project, and its impact can be

seen through:

An increase in the levelized cost of generation

A reduction in the Internal Rate of Return for the equity investor

An increase in the Net Present Value of the public participant.

Case 16 in table number 3, shows the following results for the upfront premium of US$

275,000 per MW:

The levelized cost of generation to rise to 11.34 US c/ KWh, an increase of 1.06 US c/

KWh from the base case.

The Internal Rate of Return for the equity investor reduces to 20.1%, a decrease of

428 BPS below the base case IRR,

The Net Present Value of all receivables by the public participant increases to US$

0.67 million as compared to US$ 0.22 Million in the base case

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Chart: 7 Impact of variation in Upfront premium on the IRR (Private Participant) and

the Net present Value (Public Participant)

The charts below show the effect of an increase in the upfront premium on the Levelized

cost of generation and the total project cost.

Chart: 8 Impact on variation on upfront premium on the Levelized cost of generation

US c/KWh and the Levelized tariff US c/KWh (adjusted for Revenue shared With

Hydroelectric Power Producing Areas)

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0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

NPV

Mil

lio

n US

D

IRR

(%

)

Upfront Premium USD / MW


9.00

11.00

13.00

15.00

17.00

19.00

21.00

23.00

US

c/K

Wh


Levelized cost, US c/KWh

Levelized Tarrif US c/KWh

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Chart: 9 Impact on variation on upfront premium on the Total Project Cost

(USD Million)

13.9.4 Lowest concession period

A bid based on the length of the concession period entails bidders bidding below a threshold

period set by the Public participant. The bidder proposing the lowest concession period is

allotted the project.

The project ownership returns to the public participant at the end of the concession period.

Hence earlier a project gets transferred to the Public Participant, lesser its depreciation and

greater the Net Present Value of the asset for the public participant.

Hydro power projects in PPP mode are usually allotted over a span of 20 to 40 years in

different parts of the world. Usually a period of 10 to 15 years post commissioning is

necessary to repay the project debt. Revenues in hydro power projects are a direct function

of the hydrology of the project. Project Hydrology usually has cyclical behavior with an

average year preceded by a bad year and followed by a good year. A few years post the

repayment of the project debt should be given to the private participant to benefit from the

cyclical pattern of the project hydrology.

13.9.4.1 Key benefits for the Public participant

A concession period based bid will result in shortening the period after which the project

will be returned to the Public participant. This will motivate the public participant to assist

the private participant in developing the project in the plausible timeframe and quality. The

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3.80

4.00

4.20

4.40

4.60

4.80

Mil

lio

n

US

D


Project Cost, Million USD

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public participant will also insist that the project is maintained at optimal functional

capability.

13.9.4.2 Key benefit for the Private participant

The principal benefit to the private participant in a concession period based bid is that,

there are no substantial cash outflows right at the beginning of the bid. Also, as there are no

future commitments based on the revenue generated (other than the statutory payments

such as the 30% Revenue shared with the Hydroelectric Power Producing Areas

Development Commission), the entire returns are for the project company’s benefit.

Secondly, as there is no equity or power sharing, the possibility of a dispute with the public

participant is also minimized.

13.9.4.3 Demerit of a concession based bid

The primary demerit of concession based bid is that, as the length of the concession period

decreases, the interest level and quality of maintenance of the hydro power project by the

private participant may reduce. This may affect the project facility quality with time. Also

the private participant may be motivated to install lower quality machinery to cater only to

the concession period.

13.9.4.4 Financial analysis of a lowest concession period based bid


Free Power: Nil

Free Equity: 5.0%


Concession Period: Range of 10 to 46 Years

Bidding Parameter tested: Concession Period

The concession period is the time frame in which the private participant will repay the

project debt, recover its investment and make returns on its investment. As the tenor of

project finance is usually 10 to 12 years post commissioning, it is advisable that the

concession period extends beyond the repayment tenor. The effects of variation in

concession period on financial parameters are as follows:

Table: 4 Financial Results after testing for variation in Concession Period

Sr. No. Bidding

Parameter:

Concession

Period

Levelized cost,

US c/KWh

IRR Private

Participant

(%)

NPV Public

Participant

Million USD

Case No. 1 10 11.55 19.64% 0.49

Case No. 2 12 11.05 21.76% 0.39

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Sr. No. Bidding

Parameter:

Concession

Period

Levelized cost,

US c/KWh

IRR Private

Participant

(%)

NPV Public

Participant

Million USD

Case No. 3 14 10.74 22.85% 0.32

Case No. 4 16 10.57 23.45% 0.28

Case No. 5 18 10.43 23.80% 0.25

Case No. 6 20 10.34 24.01% 0.23

Case No. 7 22 10.29 24.14% 0.23

Case No. 8 24 10.25 24.23% 0.23

Case No. 9 26 10.24 24.29% 0.22

Case No. 10 28 10.25 24.34% 0.22

Case No. 11 30 10.28 24.38% 0.22

Case No. 12 32 10.11 24.40% 0.22

Case No. 13 34 9.97 24.39% 0.22

Case No. 14 36 9.85 24.39% 0.22

Case No. 15 38 9.75 24.39% 0.22

Case No. 16 40 9.66 24.39% 0.22

Case No. 17 42 9.59 24.39% 0.22

Case No. 18 44 9.53 24.39% 0.22

Case No. 19 46 9.48 24.39% 0.22

If one bids for a concession period of 10 years, the following results were observed:

The levelized cost of generation increased to 11.55 US c/ KWh, 1.27 US c/ KWh

above the levelized cost of generation in the base case (concession period 30 years)

The Internal rate of return for the equity investor reduces to 19.64%, 474 BPS below

the base case results

The Net Present Value of all receivables to the public participant increases to US$

0.49 million.

At a concession period of 20 years, the following were observed:

The levelized cost of generation increased to 10.34 US c/ KWh, 0.07 US c/ KWh

above the levelized cost of generation in the base case

The Internal rate of return to the equity investor reduced to 24.01%, 37 BPS below

the base case results,

The Net Present Value of all receivables to the public participant increases by USD

0.01 Million to USD 0.23 million.

As observed in the charts below, the IRR increases steadily from 19.64% (10 Years) to

24.01% (20 Years) after which the increase in IRR is not substantial. Over a range of

concession periods (10 years to 46 years), the levelized cost of generation is always less than

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the levelized tariff after factoring the “Revenue shared With Hydroelectric Power Producing

Areas” (30% of total revenues), also shown in chart 8.

Chart: 10 Impact of variation of concession period on IRR (Private Participant) and the

Net present Value (Public Participant)

Chart: 11 Impact of variation of Concession period on the levelized cost and the

Levelized tariff

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0.55

18.00%

19.00%

20.00%

21.00%

22.00%

23.00%

24.00%

25.00%

10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46

NPV

fo

r P

ub

lic

Pa

rtic

ipa

nt

US

D M

illi

on

IRR

(%

) fo

r P

riv

ate

Pa

rtic

ipa

nt

Concession Period (Years)


8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46

Us

c/K

Wh

Concession Period

Levelized cost, US c/KWh Levelized Tarrif US c/KWh

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13.9.5 Highest lease or rent payment for facility

Fixed annual lease or rent payments are usually used as bidding parameters for operating

projects. In case of operating projects, the project finance and construction risks are over.

Based on historical operating performance (if available), the private participants can

evaluate the financial results of the project and provide competitive proposals for lease or

rent. The public participant also has a fair idea of their expected rental payment. Fixed

rental payments should be avoided if the project is still under development. In such a case,

variable rental payments (as a proportion of the income generated) may be a more

appropriate bidding parameter. Private participants are more likely to be interested in

committing payments in proportion to the revenue generated. This also ensures a fair

allocation of the revenue generation or hydrology variation risk of the project.

13.9.6 Lowest tariff for electricity

Electricity tariff as a bidding parameter is a common bidding parameter followed for

medium and large hydro power projects (above 25 MW). The bid is usually structured as a

discount to a specified tariff rate and the bidder with the lowest tariff is allotted the project.

In case of the proposed Omi Kampe Hydro power project, the tariff for the project is

scheduled to be governed by the MYTO II tariff mechanism outlined by the Nigerian

Electricity Regulatory Commission (NERC). Although a bid based as a discount to the MYTO II

tariff can be structured but that might put a question on the financial viability of the project.

Small hydro power project, globally are supported by the governments in the form of

subsidies (India37

), Feed in tariff (Kenya38

), Technology support (China39

) etc. Hence a tariff

based bid is not recommended for the proposed Omi Kampe small hydro power project.

13.9.7 Lowest cost of project

In bids based on lowest cost of the project, the bidders bid for the minimum cost in which

they will construct and commission the concerned project. The ownership of the project

remains with the Public Participant, and the financing may also be arranged by the Public

Participant. “Lowest cost of project” based bids are common in developing nations in

government projects funded by grants and aid from the developed nations.

For the proposed Omi Kampe Hydro power project, the “Lowest cost of project” based bid is

not feasible as the private participant is expected to invest the Equity finance and arrange

for the Project finance. Also it will be imperative that the ownership of the project be

transferred to the Project Company.

37

Source: http://bit.ly/1fSrShq Retrieved on 29 September 2013 38

Source: http://kerea.org/wp-content/uploads/2012/12/Feed-in-Tariff-Policy-2010.pdf Retrieved on 29 September 2013 39

Source: http://bit.ly/1657RRc Retrieved on 29 September 2013

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13.9.8 Combination of two or more parameters

PPP bids for hydro power project are usually structured around two or more parameters.

Parameters should be chosen so as to cancel out their individual demerits. Only one

parameter is variable (value to be bid by the Bidders) and all the other parameters are kept

fixed at pre-determined levels.

13.9.9 Proposed bid structure (Combined Case)

While a bid can be structured with a single parameter, usually two or more parameters are

used to structure bids in PPPs for small hydro power projects. Only one parameter is

variable, while all the other parameters are kept constant. One way for procurement could

also be 'lowest concession period' bid while all other parameters can be kept constant.

While each individual bidding parameter has its pros and cons, when used together they

tend to mitigate the risks the other bidding parameters pose. E.g. while free power provides

a long term revenue stream (along with an upside potential) and free equity provides a

steady stream of long term revenues, they do not provide any short term gains. This can be

made up by including the upfront premium parameter in the bid. Also a bid based on lowest

concession period may help in returning the project in a shorter span to the Public

Participants.

In this section we test for the following variables:

Free power

Free equity

Upfront premium


A base / floor level could be fixed for the selected parameters, and the bidders may bid over

and above the base level. The basic assumptions used in the financial analysis are provided

below. It should be noted that for this hypothetical situation analysis, we have varied all the

parameters simultaneously to arrive at a hypothetical best case bid scenario. In the actual

bid, only one parameter will be variable and others will be held constant.


Minimum Free Power: Nil

Minimum Free Equity: 5.0%

Base Upfront Premium: US $ 50,000

Base Concession Period: 30 Years

The results obtained on testing all the parameters together are as follows:

Table: 5 Financial Results after testing for variation in free power

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Bidding Covenants Financial Impact

Case

Number Free

Power

Free

Equity

Upfront

Premium

USD/ MW

Concession

Period

IRR Private

Participant

NPV Public

Participant

Million USD

Case No. 1 0% 5.00% 50,000 10.00 19.64% 0.49

Case No. 2 1% 6.00% 60,000 12.00 21.06% 0.49

Case No. 3 2% 7.00% 70,000 14.00 21.48% 0.52

Case No. 4 3% 8.00% 80,000 16.00 21.46% 0.59

Case No. 5 4% 9.00% 90,000 18.00 21.23% 0.69

Case No. 6 5% 10.00% 100,000 20.00 20.87% 0.79

Case No. 7 6% 11.00% 110,000 22.00 20.46% 0.91

Case No. 8 7% 12.00% 120,000 24.00 20.02% 1.03

Case No. 9 8% 13.00% 130,000 26.00 19.57% 1.15

Case No. 10 9% 14.00% 140,000 28.00 19.12% 1.27

Case No. 11 10% 15.00% 150,000 30.00 18.68% 1.39

Case No. 12 11% 16.00% 160,000 32.00 18.23% 1.50

Case No. 13 12% 17.00% 170,000 34.00 17.74% 1.61

Case No. 14 13% 18.00% 180,000 36.00 17.26% 1.73

Case No. 15 14% 19.00% 190,000 38.00 16.79% 1.84

Case No. 16 15% 20.00% 200,000 40.00 16.32% 1.95

Case No. 17 16% 21.00% 210,000 42.00 15.87% 2.06

Case No. 18 17% 22.00% 220,000 44.00 15.42% 2.17

Case No. 19 18% 23.00% 230,000 46.00 14.98% 2.27

The best case results are obtained in “Case No. 8”: The Public Participants receive the

following:

Free Power: 7%

Free Equity: 12.0%

Upfront Premium: 120,000 USD/MW

Concession Period: 24 Years (6 Years below the base concession

period)

The results obtained in case 8 are: 20.02% IRR for the Private Participant and a Net present

value of USD 1.03 Million for the public participant. The change in the IRR and NPV with

respect to each case as shown in table number 5 is displayed below in chart 9.

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Chart: 12 Impact of change in all variables (described in table 5) on IRR (Private

Participant) and the Net present Value (Public Participant)

13.9.10 Analysis of the financial parameters and choice of bid type

The following are the key observations and the implication of the choice of bidding pattern:

13.9.10.1 Project Funding:

Observation: The entire finance (Equity and Debt) will be arranged by the Private

participant

Inference: This observation rules out the following

BOT

DBO

Management contract

Reasoning: In all the above mentioned bidding patterns the Government / public participant

invests in the project

13.9.10.2 Concession period

Observation: The optimal concession period is around 24 years while factoring the

assumptions in point 10.9

Inference: Usually the bid type which extends over a period of 20 to 30 years is BOOT.

Reasoning: In a BOOT the private participant designs, finances, builds and operates the

project over a span of 20 to 30 years.

-

0.50

1.00

1.50

2.00

2.50

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

NPV

(US

D M

illi

on

) P

ub

lic

Pa

rtic

ipa

nt

retu

rn

Irr

(%)

Fo

r P

riv

ate

Pa

rtic

ipa

nt

Case NumberIRR Private Participant NPV Public Participant Million USD

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13.9.10.3 Project Ownership

Observation: The project ownership is likely to be transferred to the Project Company over

the concession period as it is expected to arrange for the equity and debt finance.

Inference: Under this observation a DBFO (Design, Build, Finance and Operate) is ruled out,

as in a DBFO the project ownership lies with the Public Participant.

Reasoning: The equity investment in developing the OMI Kampe hydro power project is

around 1.2 million USD and can be considered substantial. Also to raise the project finance,

the bank will require a first charge on the assets of the Project Company. For the above two

reasons it is imperative that the ownership the project be transferred to the Project

Company.

13.9.10.4 Risk of hydrology and Generation related risks

Observation: Variation in Revenues can be expected due to variation in hydrology, plant

availability, grid availability etc.

Inference: The concession period for the project should be in the range of 20 to 30 years.

Reasoning: Hydrology usually depicts a cyclical pattern. To harness the complete potential

of the hydro power project the Private participant should be able to cover a few

hydrological cycles.

Keeping in view the above mentioned observations, inferences and reasoning, a BOOT, i.e.

Build Own Operate Transfer, based PPP is advised for OMI Kampe Hydro power project.

13.9.11 Hydro power assets of Project Company

Under a BOOT type of PPP agreement, the Private Participant will be expected to design,

finance, build, own and operate the power plant. For construction of the power plant,

financing in the form of equity and debt capital will be raised by the project company. A

typical project finance structure will require the assets being created to be pledged to the

debt providers. The Lenders will require a first charge on the assets being created including

the machinery, land, buildings and other civil works of the project company.

A distinction may have to be made between the already existing assets and the newly

created assets financed through the project finance structure. The already existing assets

such as the dam and existing appurtenant structures are owned by the Government.

Ownership of these existing structures is unlikely to be transferred to the project company.

The government may lease these assets to the project company for a fixed (or variable/

escalating) annual lease payment. The lease agreement would define the rights and

obligations of the project company with respect to the assets owned by the Government

(e.g. maintenance of the dam, procedures for operating, etc.).

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For the sake of clarity, it is important to define the assets that will be owned by the Project

Company and therefore would be pledged to the lenders. Simply put, the Project Company

will own all assets that are created using the finances it has raised through debt and equity.

This will include all new structures such as powerhouse, machinery, switchyard,

transmission line among others. The project company would also like to own the land on

which the new structures of the power plant would be built. Since the lenders are financing

the power plant, they would require a first charge on all assets created through the money

lent by them.

Also, to establish the Project Company’s rights to construct and operate the power plant, a

few agreements may have to be executed with regards to the following rights of the Project

Company:

I. Right to abstract a specified amount of water from the Omi Kampe Dam for power

generation purpose

II. Right to modify the existing structures to suit the construction and operation of the

hydro power plant (e.g. modifications to the outlet of the dam to abstract water)

III. Right to make alternative arrangements to divert or modify the flow of water for a

specified time during execution of project works

IV. Right to control the operation of outlet gates of the dam to regulate the flow of the

water

The lenders would also require step-in rights (rights to enter the contracts and take the

place of the project company in case of default) and assignment of the project contracts

(including concession agreement, land lease, PPA among others).

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14. Environment Impact

An Environment and social impact assessment study should be conducted to assess the

social and environmental impact of the project. The ESIA should also study the

consideration of alternatives, outline and plan the mitigation or offset measures and define

the environmental and social management and monitoring plans.

The ESIA process should be conducted by involving a range of stakeholders with different

roles and responsibilities not limiting to

the developer of the project

independent consultants

Relevant authorities and government departments

External reviewers

Financial institutions

Local residents and communities

NGOs etc.

The Environment and social impact assessment should study the impact of all the phases of

the project development, namely:

Greenfield site assessment

The Construction phase

Project Operations phase

The points to be noted at each phase are as follows:

At the Greenfield site assessment phase of the hydro power project, the ESIA will need to

cover:

Details of the nature and roles of relevant stakeholders

Existing and potential land uses and forms of land tenure, appropriate governance

systems to ensure accountability and social justice

Social analysis, including the size and social structure of the local population, their

needs, wishes, skills and capacity, and an assessment of the population's health

status

Biodiversity resources and cultural heritage assets, especially protected areas and

species, and the geology, hydrology, soil quality, water resources, climatology and

meteorology of the region.

For the construction phase the ESIA should encompass the following:

Impacts on air, soil and water quality, and health and safety.

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Wastes from construction and overburden, soils and other materials.

Transitory population increase, especially any potential conflicts.

Temporary and permanent infrastructure developments.

The use and storage of explosives if needed for excavation works.

Noise, dust and vibration from construction.

During the operations phase, the ESIA will need to cover:

The social impacts, focusing on community well-being, to include

Public health and safety,

the living environment,

Satisfaction of basic needs (e.g. housing, sanitation, water supply),

Access to public services (e.g. health, education, training and recreation)

Landscape aesthetics.

Occupational health and safety of workers and contractors

Rehabilitation works if any

Environmental impacts, emissions, noise and vibration, liquid effluents and storm

water, and traffic. The ESIA should also describe the environmental management

system to be implemented.

15. Legal Framework

Pol icy and Legal Basis for The Development Of Small & Medium Hydro-

Electric Power Plants Through Publ ic Private Partnerships (PPPs)

The NEPP and the EPSRA form the basis of the legal and regulatory

environment for the NESI. In addi tion, and for the purpose of achieving

government’s goal of involving the private sector in the development and

management of infrastructure in the industry, the NPPPP and other laws

such as ICRC Act, the Privatization and Commercial i zation Act and the Public

Procurement Act amongst others are of parti cular relevance.

15 .1 The National Electric Power Pol icy (“NEPP”)

The NEPP was predicated on the need to reform the NESI to meet the needs

of Nigerians in the 21st century. The government’s priori ty is to create

effi cient market structures within clear regulatory frameworks to encourage

competi tive markets through the unbundling of the power generation and

the sale/marketing elements of the electr icity industry.

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To support thi s reform, the government sought, amongst other things, to:

update the roles of the Federal , State and Local Governments and that

of the relevant mini stry of the FGN, the Ministry of Power40;

liberalise the NESI and provide a wide range of incentives in order to

attract private participation;

establ ish a sector regulator, the Nigerian Electri city Regulatory

Commission (“NERC” ) to act as an independent regulatory agency with

the responsibi l i ty for issuing l icenses to companies operating in the

NESI, devising qual ity standards for generation, transmission ,

distribution and supply of energy and tariff regulation; and

increase access to e lectricity and rural electrif ication projects at an

affordable and cost effective manner.

(emphasi s added).

Thus, the cri ti cal pol i cy goal of the NEPP is to ensure that the NESI meets

current and future electri city demand in an efficient and economical l y viable

manner. Amongst other things, the NEPP envisaged a restructuring of the

NESI f rom monopoly, verti cal ly integrated service provision by the National

Electri c Power Authority (“NEPA” ), the erstwhile national electri c power

uti l i ty, through a transi tion involving unbundling of NEPA, and ul timately , to

a competition driven market.

To date, the NEPP remains the most definitive sector wide statement of

FGN’s pol i cies regarding the NESI.

In order to provide the appropriate legal f ramework for the reforms

envi saged by the NEPP , the FGN enacted the EPSRA in March 2005.

15 .2 The EPSRA and the Structu re of the NES I

The EPSRA was enacted wi th a view to, in the words of the NEPP , “create

effi cient market structures, wi thin clear regulatory frameworks, that

encourage more competi tive markets for electri ci ty generation and sales

(marketing) , which, at the same time, are able to attract private investor s

and ensure economical ly sound development o f the system.”41

In March 2005, the FGN enacted the EPSR Act to provide a legal f ramework

for the reforms envi saged by the NEPP . Key provi sions of the EPSR Act

include the fol lowing:

40

At the time, the Ministry was known as the Ministry of Power and Steel. 41

NEPP document – page 5.

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transfer of the employees, assets, l i abi l i t ies , rights and obl igations of

NEPA to an ini tial holding company, pr ior to the establ ishment of

successor generation, transmission and distribution companies and

the unbundling of NEPA (Part I );

development of a competi tive electri ci ty market (Part I I );

establ ishment, functions and powers of an independent sector

regulator, the NERC (Part I I I );

establ ishment of a Power Consumer Assistance Fund to subsidise

underprivi leged electri city consumers (Part VII I ); and

establ ishment of the Rural Electrifi cation Agency (“REA”) and fund to

increase rural access to electri ci ty (Part IX).

In preparation for the unbundling of NEPA, the initial holding company

was incorporated at the CAC as the Power Holding Company of Nigeria

P lc (“PHCN”). The successor companies (si x generation, one

transmission and eleven distribution) were subsequently incorporated

at the CAC in November 2005.

15 .3 The EPSRA and NERC as Industry Regulator

In l ine wi th the NPPPP , the EPSRA was enacted pursuant to the powers

granted to the NA under the CFRN, 1999 to make laws regarding the

generation, transmission and di stribution of electri city, and the

establ ishment of power stations. Parti cularly, the power to make laws for

the Federation or any part thereof wi th respect, amongst other, to:

(a) electrici ty and the establ ishment of elect ri c power stations;

(b) the generation and transmission of electricity in or to any part of the

Federation and from one State to another State;

(c) the regulat ion of the right of any person or authority to dam up or

otherwise interfere with the f low of water f rom sources in any part

of the Federat ion;

(d) the parti cipation of the Federation in any arrangement wi th another

country for the generation, transmission and distribution of electrici ty

for any area partly within and partly outside the Federation;

(e) the regulation of the right of any person or authority to use, work or

operate any plant, apparatus, equipment or work designed for the

supply or use of electr ical energy.

(emphasi s added).

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Pursuant to the above, the EPSRA sought to amongst other things, “establ is h

the Nigeria Electri ci ty Regulatory Commission, provide for the l i censing and

regulation of the generation, transmission, distribution and supply of

electrici ty; enforce such matters as performance standards, consumer rights

and obl igation; and provide for the determination of tarif fs”42.

NERC was therefore establ ished and inaugurated in October 2005 under

section 31 of the EPSRA to make regulations for , and otherwise regulate

sector activi ties. By section 32(1) of the EPSRA, the functions and powers of

NERC are, amongst others, to :

create, promote and preserve effic ient industry and marke t

structures, and to ensure the optimal ut i l ization of resources for the

provision of electri city services;

maximize access to electri ci ty services, by promoting and faci l i tating

consumer connections to distribution systems in both rural and urban

areas;

ensure that an adequate supply of electri ci ty is avai lable to

consumers;

ensure that the pri ces charged by l icensees are fai r to consumers and

are suffi cient to al low the l icensees to f inance their activi ties and to

al low for reasonable earnings for effi cient operations;

ensure the safety, security, rel iabi l i ty , and qual i ty of service in the

production and del ivery of electri ci ty to consumers;

ensure that regulation i s fai r and balanced for l i censees, consumers,

investors , and other stakeholders; and

present quarterly reports to the President and National Assembly on

its activi ties.

To actual ize the pol i cy objectives of the government as stated above, NERC

is empowered by the EPSRA to do the fol lowing:

promote competi tion and private sector parti cipation, when and

where feasible;

42 EPSRA, Explanatory Memorandum in the head note.

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establ ish or , as the case may be, approve appropriate operating codes

and safety , security, rel iabi l i ty, and qual ity standards;

establ ish appropriate consumer rights and obl igations regarding the

provision and use o f electri c services;

license and regulate persons engaged in the generation,

transmission, system operation, distr ibut ion and trading of

electricity;

approve amendments to the market rules;

monitor the operation of the electrici ty market; and

undertake such other activi ties which are necessary or convenient for

the better carrying out of or giving effect to the objects of the

Commission.

(emphasi s added).

Furthermore, pursuant to section 96 of the Act, NERC is empowered to make

regulations necessary to carry out or give effect to the provisions of the

EPSRA 43. The Act empowers NERC to make regulations wi th respect to:

the duties, powers, rights and obl igations of a l i censee;

the determination of the standards o f performance that wil l be

requi red from l icensees;

the information that wil l be required from l icensees and the manner

and form by which i t shal l be provided;

fees, levies , and other charges that may be payable by l icensees,

el igible customers or customers;

the regulatory treatment of rural electric schemes and investments;

and

the terms and condi tions for the provision of system access by

transmission and distribution l i censees to other entities.

43 EPSR Act, s. 96 (1).

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Some of the expl ici t provisions in relation to NERC’s regulatory power s

which may impact the Project shal l be further discussed below.

15 .4 The NPPPP

The NPPPP arti culates FGN’s pol icy on private sector parti cipation in the

provision of infrastructure. One of government’s key pol i cy statements in

thi s regard is “to improve the avai labi l i ty, qual ity, and effi ciency of power,

water, transport and other publ i c services in order to increase economic

growth, productivi ty, competi tiveness, and access to markets”.

The scope of FGN’s programme for PPP in the creation of new infrastructure,

and the expansion and refurbishment o f existing assets include:

power generation plants and transmission/distribution networks;

roads and bridges;

ports;

airports;

rai lways;

inland container depots and logi sti cs hubs;

gas and petroleum infrastructure, such as storage depots and

distribution pipel ines etc;

water supply, treatment and distribution systems;

sol id waste management;

educational faci l i ties (e.g. schools, universities) ;

urban transport systems;

housing;

heal thcare faci l i ties , etc 44

(emphasi s added).

Government’s legal framework for achiev ing thi s goal is to where necessary

propose amendment of existing legislation or the enactment of new

legi slation which would amongst other th ings:

ensure that publ i c authori ties are empowered to enter into

agreements for the implementation of privately financed

infrastructure projects and can delegate thei r statutory functions

to private companies;

ensure that the regulation and l icensing of publ i c service operators

and operations is transparent, timely , and effective;

44 See generally, pages 8-9 of the National PP Policy.

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create a centre of PPP experti se within ICRC (the PPP Resource

Centre) to issue guidance to al l publ ic authori ties on the

procurement of PPP projects and drafting of PPP contracts;

provide for transparent, effi cient, and competi tive procurement

procedures for PPP‐type contracts that encourage innovation from

bidders, and al low dialogue to optimise the al location of ri sks

between the contracting parties. 45

(emphasi s added).

According to the NPPPP , the FGN i s to ensure that Federal projects go

through a rigorous appraisal as to thei r economic and financial viabi l i ty

before the project begins a competi ti ve and transparent procurement

process, and the project business case is approved FGN’s Economic

Management Team or other relevant authori ty. The Federal Executive

Counci l is required to formally approve al l PPP projects prior to the award of

a contract. Whilst the ICRC is to issue regulations that speci fy a value

threshold below which these requi rements wil l not apply. It is not clear

whether such regulations have been issued by the ICRC.

The NPPPP Inst itutional Frame work

Government’s institutional framework for implementing its pol i cy for PPP

al locates specifi c roles and responsibi l i ties to various Ministries,

Departments and Agencies (“MDAs”) with in the Federal Government for PPP

project identifi cation, planning, approval, procurement, and

implementation. In addi tion, various other insti tutions are involved in the

process. These include aside from the ICRC; the National P l anning

Commission (“NPC”) which has a mandate to develop a rol l ing fi fteen (15)

year investment strategy for al l infrastructure services provided by the FGN

(National Development P lan) and incorporating the MDAs’ long- term plan for

infrastructure investment and maintenance; the Federal Ministry of Finance

(“FMOF” ), which is vested wi th the role of publ i c financial management o f

PPP projects, and of evaluating and managing fi scal risks that may resul t

from the terms of the agreements; and the Debt Management Offi ce

((“DMO” ), which in conjunction wi th the FMOF i s required to ensure that

probable contingent l i abi l i ties ari sing from a pro ject are manageable wi thin

FGN’s economic and fi scal forecasts ; the Bureau of Publi c Procurement

(“BPP”) may al so be uti l ized to ensure due process in the procurement o f

publ i c works and services.46

45 See generally, pages 5-6 of the National PP Policy. 46

See generally, pages 12-13of the National PP Policy.

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I t is expected under the NPPPP that PPP process wil l adhere to the fol lowing

outl ine 47:

Project development

identi fication of need;

a systematic appraisal of technical solutions to the identified need;

preparation of economic, social and environmental cost benefit

analysis, and an Envi ronmental Impact Assessment, i f required;

value for money (VfM) and affordabi l i ty testing of dif ferent

procurement options;

preparation of financial analysis – the pre‐feasibi l i ty study;

budget al location wi thin the National Development P lan and,

subsequently , the Medium Term Expendi ture Framework (MTEF);

approval of Outl ine Business Case (OBC) prior to the

commencement of procurement.

Procurement

creation of a project team and management structure;

preparation of an Information Memorandum and bid

documentation;

market consultation, i f appropriate;

a competiti ve and transparent procurem ent process, wi th a clear

audi t trai l for the selection of bidders and the evaluation of bids;

approval of Ful l Business Case (FBC) before the decision to award a

contract.

Implementat ion

monitoring of design and construction, and subsequently operation

and maintenance to ensure compliance with the requi red service

standards;

monitoring of payments against services del ivered and any

contingent l i abi l i ties.

Maturity

inspection and preparation for the handover of any publ ic assets in

accordance with the specified requi rements, i f appropriate;

47

See pages 19-21of the National PP Policy.

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analysis of future service del ivery options and further

procurement, i f appropriate;

contract close and recording of lessons learned.

15 .5 The ICRC

The ICRC Act was enacted in 2005 and the ICRC was inaugurated48 in line with

the NPPPP to develop the guidel ines, pol icies, and procurement processes

for PPP . Al l contracts completed in compliance wi th the ICRC Act are

guaranteed by the FGN to be legal and enforceable. The Act appl ies to

investment and development projects relat ing to any infrastructure of any

Federal Government min istry, agency, corporation or body.49

According to the Act, any MDA, such as the FMOP involved in the financing,

construction, operation or maintenance of infrastructure, i s permitted to

enter into a contract with, or grant concession to any duly pre-qual ified

private sector investor for the financing, construction, operation or

maintenance of any infrastructure that i s financial ly viable or any

development faci l i ty of the FGN. 50 The ICRC is vested with powers to take

custody of concession agreements entered into by any MDA and ensure

compliance wi th such concession terms and condi tions. Such infrastructure

projects so earmarked for concession must be submitted to the Federal

Executive Counci l for approval on the recommendation of the relevant MDA

prior to concessioning same to a private enti ty. The ICRC is responsible for

publ ishing in the Federal Gazette and at least three national newspapers

having wide circulation in Nigeria, and other simil ar means of ci rculation,

the l ist of projects el igible for contract for the financing, construction,

operation or maintenance of any infrastructure as appl i cable under the Act51

whi lst the relevant MDA, in this case the FMOP , is responsible for making

similar publ ications for the purpose of inviting open, competi tive publ i c bid

for such approved contract.52

The NPPPP al so requires the FGN to provide further guidance through the

ICRC on the effective management of each phase of a PPP project. These

include:

48

See section 14 of the ICRC Act. 49

Emphasis added. See section 1(2) of the ICRC Act. 50

Section 1(1) of the ICRC Act. 51

Section 2(4) of the ICRC Act. 52

Section 4(1) of the ICRC Act.

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project development: guidance on options apprai sal , business case

analysis, the defini tion and scope of the requirement, and value for

money and affordabi l i ty assessment;

project procurement: guidance on creating structured and

competi tive procurement processes, maintaining commercial

confidential ity , al lowing due di l igence by third party investors ,

preparing a Ful l Business Case;

project implementat ion: guidance on achieving contractual and

financial close, contract supervi sion and management, performance

moni toring and change management;

contract compliance monitoring: guidance and procedures for the

regular review of contractual obl igations, tracking the performance

of al l parties to the contract, and the resolution of any di sputes;

project maturity: guidance on project close and handover of any

publ i c assets (i f appropriate), reviews of future service needs, and

del ivery options analysis. 53

In view of the major role played by the ICRC in the management of el igibl e

PPP projects executed by MDAs, the FMOP is requi red to work closely wi th

the ICRC for the proper implementation of thi s Project.

15 .6 The Public Procurement Act

Public Procurement is the acquisi tion by any means of goods, works or

services by the government.54 In Nigeria, the National Counci l on Publi c

Procurement ( the “Counci l” ) and the Bureau of Publi c Procurement ( the

Bureau”) are the Authori ties responsible for the monitoring and oversight of

Public Procurement, harmonizing existing government pol icies and

regulating and establ ishing legal and regulatory guidel ines relating to publ i c

sector procurement. 55 The procedures for award of contract for publ i c

enti ties are to be adhered to by al l publ i c offi cers involved in publ ic

procurement in accordance with the provi sions of the Publi c P rocurement

Act, 2007 ( the “PP Act”) which al so makes provi sion for the Public

Procurement Manual ( the “Manual”) as a guide for Procuring Offi cers in the

exerci se of thei r duties.

53

See page 21 of the National PP Policy. 54

See section 60 of the PP Act. The NPPPP also defines Public procurement as the process by which government buys

goods, works, or services from the private sector.

55 See generally, the recital to the PP Act.

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The scope of appl ication of the PP Act includes amongst others , al l

procurement of goods, works, and services carried out by the FGN and al l

procurement entities. 56

Specifi c role and functions of the Bureau include amongst others57:

ensuring the appl ication of fair, competi tive, transparent and

value-for money standards and practi ces for the procurement and

disposal of publ i c assets and services;

subject to thresholds as may be set by the Counci l , certifying

Federal procurement prior to the award of contract;

supervising the implementation of establ ished procurement

pol i cies; and

reviewing the procurement and award of contract procedures of

every relevant enti ty.

In the performance of i ts duties, the Bureau is empowered to amongst

others things 58:

enforce the monetary and prior review thresholds set by the

Counci l for the appl i cation of the provisions of the PP Act by the

procuring entities;

issue certifi cate of "No Objection" for Contract Award" wi thin the

prior review threshold for al l procurements within the purview of

the PP Act;

cause to be inspected or reviewed any procurement transaction to

ensure compliance with the provi sions of the PP Act;

review and determine whether any procuring entity has violated

any provision of the PP Act;

cal l for such information, documents, records and reports in

respect o f any aspect of any procurement proceeding where a

breach, wrongdoing, default , mismanagement and or col lusion has

been al leged, reported or proved against a procuring entity or

service provider.

recommend to the Counci l , where there are persistent or serious

breaches of the PP Act or regulations or guidel ines made

thereunder - for the suspension of officers concerned wi th the

56

The Act defines procurement entities as any public body engaged in procurement and includes a Ministry, Extra-

Ministerial office, government agency, parastatal and corporation.

57 See generally, sections 4 and 5 of the PP Act.

58 See generally, section 6 of the PP Act.

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procurement or disposal proceeding in issue, or the temporary

transfer of the procuring and disposal function of a procuring and

disposing enti ty to a third party procurement agency or consultant;

null i fy the whole or any part of any procurement proceeding or

award which is in contravention of the PP Act; and

request for and obtain from any procurement entity information

including reports, memoranda and audited accounts, and other

information relevant to its functions under the PP Act.

General Principles Governin g Public Procurement

Sections 16 to 52 of the PP Act lay down a detai led procedure for publ ic

procurement. These provisions are to be appl ied by MDAs in conjunction

with the Manual. These are in l ine wi th the NPPPP which clearly requires PPP

projects to comply wi th the provisions of the PP Act and the Manual .

According to the NPPPP , the general principles governing publ i c

procurement for PPP projects should incorporate the fol lowing cri teria59:

value for money;

transparency;

fairness;

effi ciency; and

Accountabi l i ty and governance;

The Manual , in l ine wi th the above principles al so stipulates the principal

hal lmarks of profi cient Publi c Procurement to include:

Economy;

Effi ciency;

Fairness;

Reliabi l i ty;

Transparency; and

Accountabi l i ty and Ethical Standards.

Consequently, government procurement should aim to:

ensure that goods and services needed are procured wi th due

attention to economy and effi ciency;

ensure that publ i c fund is used to buy only those goods and

services needed for national development;

59

See generally, pages 27-32 of the National PP Policy.

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give al l qual i fied bidders an equal opportuni ty to compete for

contracts;

encourage development of local contractors and manufacturers;

and

ensure that the procurement process is transparent.

These principles amongst others are therefore required to be fol lowed by

the FMOP as a procuring enti ty for the procurement o f works through PPP in

respect of the Project.

15 .7 The Water Resources Act

The Water Resources Act CAP W2 LFN 2004 (“the Act”) is an Act to promote

the optimum planning, development and use of Nigeri a’s water resource s

and other matters connected therewith.

Control of Water Resources

The Act confers the Federal Government with the right to uti l ize and control

al l surface and groundwater and any water course affecting more than one

State for the purpose of planning and developing Nigeria’s water resources;

coordinating activi ties that affect the qual ity , quanti ty, di stribution , use and

management of water; applying techniques and standards for investigating,

control l ing, protecting, managing and administering water resources; and

faci l i tating technical assistance and rehab i l itation for water supply.

Right to Use Water

Any individual or MDA that wishes to acquire a right to use or take water

from any watercourse or any speci fied groundwater for any purpose must do

so in accordance wi th the provi sions of Water Resources Act. As prescribed

by the Act, the Federal Mini stry of Water Resources, headed by the Minister

of Water Resources (“the Minister”) is the main government agency

responsible for the management and control of water resources in Nigeria.

Licensing

The Minister under the Act is empowered to issue a l i cense for the

diversion, storage, pumping or use on a commercial scale of any water;

construction, maintenance, operation or repair of any hydraul ic works. The

Act further empowers the Minister to impose fees on such l icenses granted

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to individuals or MDA’s seeking to construct, operate, maintain, repai r or

al ter any hydraul i c works in or adjacent to any water source60.

Limitations to Rights and Licenses

The right to uti l ize water may be revoked by the Minister when such right i s

l ikely to override publ ic interest61. Furthermore, the Minister upon

considering the al location of usable water in the watercourse or

groundwater in the parti cular area may:

refuse to issue a l i cense i f the l i censee’s activi ties are l ikely to

interfere wi th the quantity or qual ity of water;

cancel or modify an exi sting l i cense to accommodate the needs of

another l icensee; and

modify, suspend or cancel a l icense on account of non-use of such

l icense. 62

Impo sit ion of fees, rates and charges

The Minister under the Act may by regulation or otherwise prescribe charges

to any MDA in connection with i ts provision of service. This shal l include any

charge by way of contribution to the cost o f any works associated wi th the

provision of such services paid for f rom public fun ds63.

Therefore, the Water Li cense wil l be required to be obtained from the

Federal Mini ster of Water Resources for the project.

15 .8 The NESREA Act

The National Envi ronmental Standards and R egulations Enforcement Agency

(Establ ishment) Act, 2007 ( the “Act”) is to provide for the establ ishment of

the National Envi ronmental Standard and Regulations Agency (“the

"Agency” ) under the Federal Mini stry of Environment, charged with the

responsibi l i ty of protecting and developing the Nigerian envi ronment and

other related matters.

Functions of the Agency

The Agency is empowered under section 7(d) to enforce compliance wi th

pol i cies , standards, legi slation and guidel ines on water qual ity,

60

See generally sections 9 – 13 Water Resources Act 61

Section 4 (d) Water Resources Act 62

Section 11 Water Resources Act 63

Section 14 Water Resources Act

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environmental heal th and sani tation, including pol lution64 abatement. The

Agency is also permitted to prohibi t processes and use o f equipment or

technology that undermines environmental qual ity.

Power to make Guidelines on Dams and Reservoirs

Pursuant to section 26(1) of the Act, the Agency is empowered to make

regulations, guidel ines and standards for the protection and enhancement of

water qual ity , dams and reservoirs and for watershed management.

The operations of the Dams and i ts adjoining faci l i ties may therefore be

subject to such regulations, guidel ines and standards as the Agency may

from time to time make for the protection and enhancement of the qual ity

of the envi ronment. We are not aware of any such guidel ines or regulations

issued by NESREA.

15 .9 Environmental Impact Assessment Act

The EIA Act sets out the general principles, procedure and methods to

enable the prior consideration of environmental impact assessment on

certain publ ic or private projects. According to the Act, an EIA i s requi red by

any individual , body corporate or an authority (MDAs inclusive) , in arriving

at a deci sion to undertake certain activi ties (including power generation) , in

order to establ ish matters that may signif icantly affect the environment.

The Act mandates that no project is to be embarked upon wi thout prior

consideration for environment and in the event the extent, nature or

location of a project i s l i kely to signifi cantly affect the environment, an EIA

shal l be undertaken in accordance with the provi sions of the Act.

Section 13 (d) of the EIA Act stipulates that an EIA is required where a

Federal authority establ ished by the Federal Government under the

provisions of any law and enactment, issues a permi t or l icense or grants an

approval or takes any action for the purpose of enabling a project to be

carried out .

All institutions (private and publ ic al ike) that intend to carry out projects

are to apply in writing to the Nigerian Environmental Protection Agency ( the

“Agency” ) who in turn wil l identify the relevant envi ronmental issues. The

Act stipulates that no government authori ty shal l permit any project

described in the mandatory study l ist in the Schedule to the Act to be

64

Pollution according to the NESREA Act means man made or man-aided alteration of chemical, physical or biological

quality of the environment beyond acceptable limits and “pollutants” shall be construed accordingly. It is our view that oil

or LNG will be a pollutant for the purpose of this provision.

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carried out unti l the Agency has taken a cause of action conducive to it s

power under the Act or has taken a deci sion that a project be carried out. 65

I t is important to note that paragraph 13 of the Schedule makes parti cular

reference to Power generation and transmission projects and in addition,

dams and hydro-electri c power schemes are stipulated as part of the

mandatory study l ist.

Upon the Agency determining that there is a need for an environmental

assessment to be carried out, a screening or mandatory study report of the

project i s to be prepared. The report shal l consider the fol lowing amongst

others:

Environmental ef fects of the project;

Signifi cance of the project;

Comments on the project received from the publ i c;

Measures that would mi tigate the effects of the project;

Alternative means of carrying out the project and their

environmental effects thereof;

Fol low up requirements in respect of the project; and

Short or long term capaci ty for regeneration of renewal resources

that are to be affected by the project.

The Agency shal l use al l information avai lable to conduct a screen of the

project and upon completion, i f in the opinion of the Agency the project i s

not l ikely to cause any adverse signifi cant envi ronmental effect or i f such

effects can be mi tigated, the Agency may permit such project to be carried

out. However, i f in the opinion of the Agency the p roject poses advers e

environmental effects that may not be mi tigable or i f publ ic concerns as

regards the environmental effects of the project warrants i t, the Agency may

refer the project to the Federal Envi ronmental Protection Counci l (“the

Counci l”) for a referral to mediation or a review by a panel created by the

Counci l in conjunction wi th the Agency.

Therefore, the FMOP in embarking on its concession of dams for the purpose

of generating Hydro-electri c power wil l be required to comply with the

provisions of the Act by conducting an Environmental Impact Assessment of

the Project and obtaining the relevant Agency permit in accordance wi th the

EIA Procedure and sectoral guidel ines establ ished by the Federal Ministry of

Environment.

65

See section 12 of the EIA Act.

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15 .10 The River Basins Development Au tho rities Act

The River Basins Development Authori t ies Act (“the Act”) i s an Act to

establ ish River Basins Development Authorities in Nigeria.

The Act establ ishes the fol lowing River Basin Development Authorities:

Authority Area of Operat ion 66 Head-Quarters

Anambra-Imo River Basin

Development Authori ty.

The whole o f

Anambra and Imo

states.

Owerri .

Benin-Owena River Basin


The whole of Bendel

and Ondo States

excluding those parts

of B endel State

drained by the Benin,

Escravos, Forcados

and Ramos Rivers

creek systems.

Benin.

Chad Basin


The whole of Borno

State excluding those

parts drained by the

Jama’are and Misau

Rivers system but

including those parts

of Gongola State

drained by the

Yedseram and Goma

River systems.

Maiduguri .

Cross River Basin

development Authority.

The whole of Cross-

River State.

Calabar.

Hadejia-Jama’are Tiver

Basin Development

Authori ty.

The whole of Kano

state and those parts

of Bauchi and Borno

States drained by the

Jama’are and misau

Rivers systems.

Kano.

Lower Benue River Basin


The whole of Benue

and P l ateau State.

Makurdi.

Niger Delta Basin


The whole of Rivers

state and those parts

of Bendel State

drained by Benin,

Escravos, Forcardos

and Ramos Rivers

Port Harcourt.

66

Please note that the Area of Operations mentioned in the Act depicts the States of the federation in existence as at 1986

of 202

Authority Area of Operat ion 66 Head-Quarters

creek systems.

Niger River Basin


The whole of Kwara

and Niger States; the

Federal Capital

Territory; whole o f

Kaduna State

excluding Katsina

State.

Minna.

Ogun-Oshun River Basin


The whole of Oyo,

Ogun and Lagos

States.

Abeokuta.

Upper Benue River Basin

development Authority.

Those parts of Bauchi

State drained by the

Gongola State

drained by the

Gongola River

system; the whole of

Gongola State

excluding those parts

drained by the

Yedeseram River

system.

Yola

Sokoto-Rima River Basin


The whole of Sokoto

State and Katsina

State.

Sokoto.

Functions of each Authority

The Act stipulates that each of the Authorities shal l :

Undertake development of al l water resources for the provision of

irrigation infrastructure and control of floods and erosion and for

water-shed management;

Construct, operate and maintain dams, dykes, polders , wel ls,

boreholes, ir rigation and drainage systems, and necessary functions

and hand over al l lands to be cul tivated under the irrigation scheme to

the farmers;

Supply water from completed storage schemes to al l users for a fee a s

it may determine with the approval of the Minister of Water

resources;

Construct, operate and maintain infrastructure that form an integral

part of the Authority ’s approved project; and

Develop a water resource Master P l an by col lating data relevant from

its respective ri ver Basin.

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The Authori ties are also empowered to make bye-laws for the management

of irrigation schemes and regulating the use of water resources wi th respect

to the functions l isted above. Such bye-laws are subject to presidential

confirmation.

The Request for Proposal issued by the FMOP describes the location of each

dam to be concessioned. I t is our observation that the Doma Dam in

Nasarawa State is under the control of the Lower Benue River Basin

Development Authori ty, the Sokoto-Rima River Basin Development Authority

is in charge of the Bakolori Dam in Zamfara State and the Kampe Dam in Kogi

State is run by the Niger River Basin Development Authority.

In order for the FMOP to uti l ize the dams for the purpose of generating

hydro-electri c energy, i t wi l l need to enter into necessary arrangements with

the relevant River Basin Development Authori ties created under this Act

prior to concessioning the dams. It should be noted however that under the

Privati sation and Commercial isation Act 67, the above mentioned River Basin

Development Authori ties are to be partial ly commercial ised. It may

therefore be necessary in obtaining relevant permits from these Authori ties

to also consul t with the Bureau of Public Enterprises which in consul tation

with the National Counci l on Privati sation can determine the proper mode of

the permit to be i ssued by each Authori ty in l ine wi th i ts function of

preparing publ ic enterpri ses approved for commercial isation. It would be

necessary for the FMOP to ensure that any permit so obtained would be

val id and subsi sting notwi thstanding the subsequent partial

commercial ization of these Authori ties and the resul tant change of each

Authori ty’s Management.

15 .11 Hydroelectric Power Producing Areas Development Commission

(Establ ishment) Act

The Hydroelectri c Power Producing Areas Development Commission

(Establ ishment) Act (the “Act”) establ ishes the Hydroelectri c Power

Producing Areas Development Commission ( the “Commission”) which i s

charged wi th the responsibi l i ty of managing the ecological menace due to

operations of dams and other related matters.

According to the Act, the hydroelectri c power producing areas are made up

of the fol lowing Member States:

Kebbi;

67

See Part I of the Second Schedule to the Act

of 202

Kogi ;

Kwara;

Niger;

P lateau; and any other State where hydroelectri c power i s

produced.

Functions of the Commission

The functions of the Commission are to :

Formulate pol icies and guidel ines for the development of

hydroelectri c power producing areas;

Implement programmes for the development of power producing

areas;

Prepare schemes to promote the development of power producing

areas;

Identify factors inhibi ting the development of hydroelectri c power

producing areas;

Provide reports on projects being funded in hydroelectri c power

producing areas;

Tackle ecological problems resulting from overloading of dams and

advi sing the government on the prevention and control of floods

in hydroelectri c power producing areas; and

Carry out any other function the president may di rect.

Funds the Commission

The Commission i s to maintain a fund which shal l be derived from:

30% of total revenue generated by any company or authority from

the operation of any hydroelectri c dam in any Member State of the

commission;

50% of money due to member states of the Commission from

Ecological Funds;

Gifts, loans, grant-in-aid , testamentary disposi tion or otherwise;

Proceeds from the Commission’s assets; and

The annual budget.

The activities of the FMOP (or i ts concessionaires) in relation to the

operation of the concessioned dams in hydroelectri c power producing area s

would be subject to the pol i cies and programmes of the Commission.

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I t should also be noted that by vi rtue of section 14(1) of the act, 30% of the

total revenue generated by hydroelectri c dams is to be paid and credited to

the funds of the Commission.

This means that 30% of the gross income (and not the profits) generated by

each of the concessioned dams are to be remitted as funds of the

Commission.

15 .12 NERC’s Regulations and Codes of Pract ice

Of parti cular relevance to the Project are regulations deal ing with the

fol lowing:

Procedures relating to Li cense appl ication, modifi cation and

cancel lation;

Duties, powers, rights and obl igations of a Li censee;

Licensee’s standards of performance;

Determination of Tarif fs and procedures;

Fees, levies and other charges payable by Li censees; and

Connection to the grid.

15 .12.1. Generation L icensing Regulat ions/Requirements

Pursuant to section 64 of the EPSRA, NER C is empowered to i ssue generation

l icences, hydro or otherwise, based on terms and condi tions as it may fi x in

the l i cence. A generation l icence shal l , as the circumstances may require,

authorise the l i censee to construct, own, operate and maintain a generation

station for purposes of generation and supply of el ectri ci ty in accordance

with the provisions of the EPSRA. Such generation l i cences may be i ssued to:

(a) One or more of the successor companies formed under section 8 of

the EPSRA, i .e. , “successor generation company”;

(b) One or more enti ties that are not successor companies formed under

section 8 of the EPSRA, i.e., “ Independent Power Producers” 68; or

(c) Prospective embedded generators69.

Section 62(1) & (2) of the EPSRA al so provides that except in accordance

with a l i cense issued in compliance wi th i ts provisions, no person (except for

68

The Independent Power Producers (“IPPs”) are either privately owned or are government sponsored initiatives which

provide competition to the successor generation companies. This generation licence permits the licensee to carry on the

business of electricity generation and sale of power through the national grid and provision of ancillary services.

69

Embedded Generation is the generation of electricity directly connected to and evacuated through a distribution system

which is connected to a transmission network operated by a Systems Operations Licensee.

of 202

the purpose of generating captive power 70 and electri city not exceeding 1

megawatt (MW) in aggregate at a si te or an undertaking for distribution for

electrici ty wi th a capaci ty not exceeding 100 ki lowatts (kW) in aggregate at a

site), may construct, own or operate an electri ci ty undertaking or in any way

engage in the business of :

a) electrici ty generation;

b) electrici ty transmission;

c) system operation;

d) electrici ty distribution; or

e) trading in electri ci ty.

Thus, amongst the categories of l i cences which can be i ssued by NERC i s the

generation l i cence which enables the holder to construct, own, operate and

maintain a generation station for purposes of generation and supply of

electrici ty - a generation l icensee may be a Genco as specified under section

8 of the EPSR Act, or a publ ic or private sector IPP parti cipant71.

In addition to the terms outl ined specifi cal l y in the EPSRA, NERC is

empowered to fi x terms and condi tions to generating l icences. The terms

and conditions of the l icense may be amended at the behest of the l icensee,

or on the direct initiative of NERC. Thus, a generation l icence issued by NERC

is usual ly accompanied by a Generat ion License – Terms & Conditions which

l icensees are compelled to abide by.

NERC has i ssued three regulations which impact on l icences. These are:

The Regulations for Appl ication for Li cence (Generation,

Transmission, System Operations, Di stribution & Trading) 2010 (the

“Li cence Appli cation Regulations”) ;

The Regulations for Li cence and Operating Fees Regulation 2010

(the “Li cence Fees R egulations”); and

The Reporting Compliance Regulation, 2009.

Application for License Procedure

The relevant provi sions of the Li cence Application Regulations include those

related to l i cence amendment, renewal , extension of tenure, suspension and

cancel lation. Under the EPSRA, upon app l ication a l icence may be issued for

70

Captive Generation is defined as generation of electricity for the purpose of consumption by the generator and which is

consumed by the generator itself, and not sold to a third-party. Where the capacity exceeds 1 MW, a permit must be

obtained from NERC.

71

EPSR Act, s. 64.

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not more than 10 years initial ly , the term of which may be extended for an

addi tional maximum of 5 years. The Regu lations provide that any appl ication

for extension of tenure must be done wi thin the first 5 years of the initial

term of the l i cence and an appl i cation for extension of tenure may only be

granted once during the ini tial term of the l icence.

An Application for a l icence is required to be made in writing addressed to

the Chairman of NERC and al l such appl ications shal l be accompanied wi th

al l the information specified in the Appli cation Form.

Mandatory Submissions for Application s for Generat ion L icences

An appl ication for a generation l icence shal l be accompanied by the

fol lowing:

1. Completed Appli cation Form;

2. Certifi cate of Incorporation and Memorandum and Arti cles of

Association, or Deed of Partnership, or Deed of Trust;

3. Registered Ti tle Deed to Si te, or Sale Agreement, or Deed of

Assignment/Gift, or evidence of submission of a ti tle deed to a

relevant land processing agency (as appl icable);

4. Tax Clearance Certifi cate for immediate past three (3) years;

5. Ten-year Business P l an;

6. Off-take Agreement or Arrangement;

7. Environmental Impact Assessment (EIA) Approval Certifi cate, or

Proof of submission and acceptance for processing of the Report

on EIA to the Ministry of Envi ronment, or Detai ls on how

effluents and di scharges wil l be managed (i f proposed capaci ty

is less than 10MW);

8. Fuel Supply Agreement, or a letter f rom a fuel suppl ier and

transporter indicating the inclusion of the fuel needs of the

appl i cant in the supply plans of the fuel suppl ier and

transporter;

9. MoU with or Letter o f intent from Engineering Procurement

Contract (EPC) Contractor (i f appl icable);

10. MoU with or Letter of Intent from the technical partner (i f

appl i cable) ;

11. Financing Agreements or Letter to fund the project f rom

financial institution(s);

12. Timelines for commissioning of the power plant and on the date

when di fferent capacities of the plant wil l come into operation.

General Requirements for Generat ion L icences

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1. Si te Map: Showing fuel del ivery and storage locations,

transmission evacuation si te, water pipel ines, gaseous, l iquid

and sol id waste di sposal areas etc.;

2. Location Map: Showing Roads, Rai l Lines, Transmission Lines,

Rivers, Reservoirs , etc. ;

3. A principal single-l ine diagram of the project si te ;

4. Fuel Sourcing, Transportation and Supply Arrangements;

5. Water supply and avai labi l i ty analysis for plant and staff use;

6. P lant Design;

7. Power Station Information:

a. Total capaci ty (MW)

b. Number of Generating Uni ts

c. Size of Generating Units (MW)

d. Expected Annual Generation (MWh)

e. P roposed Running Regime

f. Station Load/Load Factor

8. Generator Uni t Information:

a. Generator Type

b. Rating (MVA, MW)

c. Terminal Vol tage (KV)

d. Rated Frequency

e. Rated speed (RPM)

f. Automatic Frequency Control Faci l i ty

g. R ated Power Factor

h. Uni t Ef fi ciency

i . Short C ircuit Ratio

j . Di rect Axi s Transient Reactance

k. Direct Axis Sub-transient Reactance

l . Quadrature Axis transient reactance

m. Generator Cool ing (Air-cooled, Hydrogen etc)

n. Auxi l iary Power Requirements

o. Type of Exci ter (Stati c or Rotating, Self or Separately Exci ted)

p. AVR type

q. Generator Protection (Relays)

r. Type and Characteri sti cs of Governor Control System

s. Generator Uni t Transformer Data

t. Manufacturer ’s name / Year of Manufacture / Warranty

9. Engineering, Procurement and Construction (EPC) Contract.

(P lease refer to the report on the Guide to the Development o f

Independent Power P l ants);

10. Detai ls of Phasing of Project, i f appl icable;

11. Auxi l iary Systems: P l ease refer to the report on the Guide to the

Development of IPPs.

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12. Anci l lary Services:

a. Black Start faci l i ties

b. Reactive Power Generation capabi l ities

c. Frequency Response Capabi l ity

d. Maximum Generation (MAXGEN) capabi l ity

e. Fast Start capabi l ity

13. Report of evacuation studies (For Grid Connection) :

a. Load Flow Studies

b. Stabi l i ty Studies

c. Short Circuit Studies

14. Station Safety Arrangements:

a. Emergency Response P lan

b. Fire Fighting Faci l i ties

c. First Aid

d. Safety Awareness and Staff Training P l ans

e. Personal Protective Equipment (PPE)

f. Heal th & Safety Poli cy

15. Environmental Impact Assessment (EIA) and Waste Management

P lan.

16. Expected date of Commissioning

17. Evidence of approval from Transmission Company of Nigeria

(TCN) confirming that proposed connection point has capaci ty to

take load which wil l be fed to i t Connection.

Specif ic Requirements for Generation Licences - Hydro Plants:

1. Agreement/Approval wi th Ministry of Water Resources

2. Map showing proposed Dam Reservoir Area, Water conductor

system, fore bay, power house etc.

3. Information on area of vi l lage, forestland, agri cul tural l and, etc

submerged.

Turbine Unit Information (Hydro Turbines):

1. Turbine Type (Franci s, K aplan , Pel ton)

2. Nominal Head (Metres)

3. Nominal Water Flow (M3/S)

4. Turbine Capaci ty (MW)

5. Turbine Effi ciency

6. Hydro Governor Type

7. Block diagram for the speed governor

8. Noise Level

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9. Manufacturer ’s name / Year of Manufacture / Warranty

Specif ic Requiremen ts fo r EMBEDDED Generation/ Off-Grid Generation

Licence:

1. Total Capaci ty per si te

2. Number of Generating Units per site

3. Fuel Type

4. Si ze of Generating Uni ts (MW & MVA)

5. Terminal Voltage

6. Rated Power Factor

7. Reactive Power Capacity (i f any)

8. Noise Level

9. System Protection

10. Waste management plan or EIA (If requi red)

11. Agreement or Arrangement wi th Distribution Company for

Network use.

12. Manufacturer ’s name / Year of Manufacture /

Right of Access to Land

Where the concessionaire’s generated power is to be sold to the grid, i t wi l l

requi re a connection to the transmission network which would be carried

out by TCN. However, in the event that the power generated is to be sold to

a third party off-grid and the concessionaire i s required under any

agreement with a third party to make the necessary connections to the

transmission network for onward del ivery of the power generated, it would

requi re a right of access to land. Where this is the case, an appl i cation

would need to be made to NERC for an access right over land , bui ldings and

streets for the purpose of discharging i ts obl igations under the l i cense. 72

15 .12.2. Tariff Regulation 73

NERC i s empowered under the EPSRA to regulate pri ces of electri ci ty with

regard to generation and trading74, transmission, distribution and system

operation activities, in respect of which a l icence is required under the

EPSRA.

72

Section 77 (1) and (10) of the EPSRA 73

EPSR Act, s. 76. 74

To the extent that NERC deems it necessary to do so in order to prevent abuse of market power.

of 202

Section 32(d) and (f ) o f the EPSRA mandates NERC to ensure a fair pri cing

and regulatory regime to consumers, l icensees, investors and stakeholders in

the industry. By virtue of sections 76, 80 and 81 of the Act, NERC has a duty

to regulate tarif fs , set consumer protection and performance standards in

respect of electri city services for which l icenses are required under the Act.

Pursuant to the above provi sions, NERC has i ssued the Mul ti Year Tari ff

Order (“MYTO” ) amended from time to time, which is designed to ensure,

over a number of years, gradual increase in the End-User Tarif f for

electrici ty consumers in Nigeria.

15 .12.3. The Grid Code

The Grid Code contains the day to day operating procedures and principles

governing the development, maintenance and operation of an effective, wel l

coordinated and economic transmission system for the NESI. Thus where the

project envisages the provi sion of power to the main grid at any stage in i ts

operations, i ts use of the transmission system shal l be governed by the

provisions of this Code. The Code serves to regulate the use of the

transmission system by al l users and the users’ rel ationship wi th the

Transmission Company of Nigeria (“TCN”) as the Transmission Service

Provider (“TSP”) and System Operator. The Code also speci fies the technical

requi rements for the relevant plant.

15 .12.4. The Market Rules

The Market Rules (the “Rules” ) complement and supplement the Grid Code

and together the two documents constitute the rules for the planning,

dispatch and operation of the system and the administration of the

wholesale electri ci ty market in Nigeria. The Rules serve to establ ish and

govern an effi cient, competiti ve, transparent and rel iable market for the

sale and purchase of wholesale electri ci ty and anci l lary services in Nigeria

and ensure that the Grid Code and the Market Rules work together to secur e

effi cient co-ordination and adequate part icipation. I t aims to:

Provide a framework for an eff i cient, competi tive, transparent and

rel iable wholesale electri city market;

Set out the responsibi l i ties of Parti cipants, the TSP , the System

Operator and the Market Operator in relation to trading, co-

ordination, di spatch and contract nomination, pri cing of

imbalances and Anci l lary Services, metering, settlement and

payments;

Provide for the operation and pri cing system of the Balancing

Market;

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Ensure an effi cient, transparent and predictable settlement system

and

Set out the payment obl igations;

Establ ish a governance mechanism and a market moni toring

system;

Provide a framework for resolution of di sputes amongst

Parti cipants 75 or between Parti cipants on one hand and the System

Operator or the Market Operator on the other, on matters relating

to the Market Rules and the Grid Code; and

Provide an effi cient and transparent process for amending the

Market Rules and the Grid Code.

To be regarded as a Parti cipant in the wholesale electri ci ty market, a

l icensee must fulfi l l the fol lowing requi rements amongst others:

must hold a l icense authorizing the conduct of Generation or

Distribution business or is otherwise authori zed by NERC to carry

on business as a Generator or Distributor; or

must own small Generation or Sel f -Generation and i s authorized by

NERC as a Generator;

must have instal led a C ommercial Metering System at each

Connection Point;

must have submitted an Application to the Market Operator for

admission in to the Market and has obtained registration as a

Parti cipant pursuant to fulfi l l ing al l registration requi rements as

stipulated by the Commission.

Other parties to the Market Rules are:

The System Operator who i s responsible for planning, dispatch and

operation of the power system and implementation of open access and new

connections of equipment or loads to the System Operator Control led Grid

in l ine wi th the functions establ ished in the Grid Code, and in accordance to

its l icense; and

The Market Op erator, responsible for implementing and operating the

Market in a manner designed to guarantee an effi cient, transparent and non-

discriminatory market administration service to al l Parti cipants, faci l i tate

the development of a sustainable competitive Market, and adapt to regional

Markets or regional electri city trading agreements.

75

“Participants” is defined in the Rules as any person who is a party to a Market Participation Agreement, in addition to the

Market Operator. A Market Participation Agreement is the Agreement pursuant to which the Rules and the Grid Code are

made binding on a Participant.

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15 .12.5. NERC Model Agree ments

In operating as an IPP , a l i censee needs to enter in to various agreements,

some of the key agreements aside from the Operations and Maintenance

Agreement, include NERC regulated agreements related to grid connected

transmission:

Conn ection and the use of Electricity Transmission Network Agreement

This agreement regulates the relations between the user of the transmission

network and the TCN. It would cover i ssues such as the condi tions for right

to use and connect to the electri ci ty transmission network, the relevant

charges to be paid and the mode of payment, the metering system to be

employed, obl igations of the parties, right of access to the network, safety

rules , securi ty and compliance with appl icable laws, new connect site

requi rements, etc. A proper grasp of such issues wi l l be required by an IPP

to effectively perform its obl igations;

Interface Agreement

The Interface Agreement deals wi th the interaction of personnel and

operation of equipment and faci l i ties at a connection site between the

network operator and i ts user. The Agreement spel ls out the terms involved

in the connection of equipment to the grid and covers issues such as right of

access, dispute resolution, right to instal l and retain assets, relocations and

removals , services and use of assets etc. ;

Ancil lary Services Agreement

This Agreement deals wi th anci l lary services to the network for the purpose

of ensuring a safe, stable and rel iable operation of the network and other

external ly connected networks. As a result o f some of the provisions of the

Grid Code, a generating plant connected to the grid wil l have to provide

anci l lary services such as vol tage control , black start capabi l ity, operating

reserves and a host of others. Issues such as the aforementioned ones would

need to be agreed upon by both the network operator and the IPP . As

previously indicated, for the purposes of the Market Rules, al l power sales

agreements would be requi red to include provisions that impose an

obl igation on the sel ler to provide anci l lary servi ces.

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15 .12.6. The Nigerian Electric ity Regulatory Commission Regulations for

Embedded Generat ion, 2011

The Nigerian Electri ci ty Regulatory Commission Regulations for Embedded

Generation, 2011 ( the “Regulations”) seeks to regulate the operations of

embedded generators, prospective embedded generators and appl ications

for embedded generation76 Li censes. It also makes several provisions to

regulate the interaction between embedded generators and distribution

l icensees.

Where the Project envi sages that the IPP would provide power to a Di sco as

an Embedded Generator, the fol lowing shal l be appl icable.

Application

An appl ication by a prospective embedded generator i s governed by the

provisions of the Appl ication for Li censes Regulations and the Li cense and

Operation Fees Regulations77. However, as stipulated by the Regulations,

such an appl i cation wil l not be granted unless there is compliance with Rules

22.4.1 and 22.4.2 of the Market Rules. Rules 22.4.1 of the Market Rules

provide that a Disco may purchase embedded generation to provide for local

rel iabi l i ty reserves due to transmission constraints ; however, to justify such

purchase, NERC may request an evaluation by the System Operator to verify

that the need for such local reserve i s necessary. Sub ject to the above

mentioned provi sion, Rule 22.4.2 provides that a Disco is prohibi ted from

entering into a bi lateral contract with an embedded generator unless one or

both of the fol lowing conditions have been satisfied:

A Disco is acting alone or in conjunction with other Di scos, and

upon receipt of a proposal for power procurement by the Bulk

Trader proposes an al ternative bi lateral contract at lower pri ces

than the pri ces of the new power procurement proposed by the

Bulk Trader and the Disco(s) ’s proposal is approved by NERC; or

Where there are transmission constraints that cause shortages in

the Discos(s) coverage area and i t is expected that such constraints

wil l remain for at least five (5) years , and the Disco fol lows a

competi tive process, wi thin the guidel ines establ i shed by NERC to

procure generation instal led or connected in i ts region.

76

Embedded Generation is defined as the “generation of electricity directly connected to and evacuated through a

distribution system which is connected to a transmission network operated by a Systems Operations Licensee” See

Regulation 3 77

See Rule 1, Chapter VII of the Regulations.

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The Regulations al so provide that an affi l iate of an embedded generator may

be l icensed to engage in the business of distribution, transmission, trading

and system operations provided that NERC is satisfied that the appl icant wil l

not abuse i ts market power to the detriment of consumers or that

appropriate safeguards exi st to prevent such abuse. Separate accounts are

also required to be kept by the embedded generator and i ts l i censed

affi l iate.78

Conn ection of Embedded Generation

The Regulations provide that the maximum embedded generation capaci ty

al lowable for a given di stribution system except for an isolated Independent

Electri ci ty Di stribution Network (“IEDN” ), shal l be a percentage of the pea k

system load of the Disco’s distribution system to be determined by NERC.

Embedded generations uni ts above 5MW are requi red to comply with

appl i cable provi sions of the Grid Code except those connected to an i solated

IEDN. However, embedded generation units with capaci ty of 20 MW and

above are required to be dispatched central ly by the System Operator in

accordance with the provisions of NEPP . In addi tion, the Regulations

mandate a Di sco to make access to the distribution systems avai lable to the

embedded generator in so far as there is capaci ty and after reaching an

agreement with the generator on the acceptable connection condi tions and

fees. The Regulations al so prescribe that the procurement o f power should

be competi ti ve and in accordance wi th the provisions of the Bulk Generation

and Procurement Guidel ines and Codes approved by NERC.79

The embedded generator and the Disco are requi red to enter into a host of

agreements to govern their relationship . The Disco is required to develop

and publ ish a template of the Power Purchase Agreement, Connection

Agreement/Interface Agreement, Use of Networks Agreement and Anci l lar y

Services Agreement along with the standard terms and condi tions approved

by NERC. Such agreements would form the basi s of negotiations between the

embedded generator and the Disco. The Disco and the embedded generator

may in their PPA determine the charges, and any relevant securi ty for such

charges, that may be paid by the Disco to the embedded generator for such

capaci ty and energy that is made avai lable to the Disco. However, such

charges must be in accordance wi th the tarif f methodology in force as

approved by NERC.

78

See Rule 1 of Chapter VIII of the Regulations. 79

See Rule 7 Chapter III of the Regulations.

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15 .13 Conclusion of the Legal and regulatory framewo rk

Our review of the legal and regulatory framework clearly indicates that the

FMOP is empowered under the NPPPP and the ICRC Act to carry out the

Project in l ine wi th the provisions of the ICRC Act, the Publi c procurement

Act and its accompanying Manual. Consi stent compliance wi th the provisions

of these Acts is a requi red for the Project to be val idly executed.

As already stated above, in execution this Project, the FMOP would need to

interface with the fol lowing government agencies amongst others:

The ICRC

As the authori ty vested with the powers to take custody of concession

agreements entered in to by any MDA, the FMOP i s required to work closely

with the ICRC in the implementation of the Project. I t is our understanding

that the FMOP is already in col laboration with the ICRC on the Project. Thi s

col laboration is requi red to subsi st throughout the Project cycle vi z , f rom

Project inception to completion and hand-over of Project at the

contractual ly stipulated end of the concession;

The Federal Ministry of Environment

The FMOP should aim to ensure proper compliance with the EIA Procedure

and sectoral guidel ines establ ished by the Federal Mini stry of Environment

regarding EIA. Thi s in parti cular would requi re prior submission of an EIA

report and consul tations wi th the Ministry on the impact of the Project on

the environment and mitigation measures required i f any.

The River Basins Development Authorities

Interested private investors in considering parti cipation in the P roject would

need to be assured that relevant permits and l i cences required for Project

execution has been granted or would be granted in a timely manner without

any impediment. To that extent, the FMOP would need to engage wi th the

River Basins Authori ties and the BPE for the purpose of obtaining the

relevant permits required for the legal concessioning of the dams. As owner ,

the River Basin Authori ties wil l be required to be a party to the concession

agreement.

The Ministry Of Water Resources

For the FMOP ( through its concessionaires) to construct, operate and

maintain hydro-electri c dams and harness hydro-electri c energy from such

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dams, i t needs to obtain the relevant l icences from the Federal Minister of

Water Resources. For any o f the Dams which have not initial ly received such

l icence, the FMOP would need to initiate di scussions wi th the Minister of

Water Resources for the grant of such l icences. The timing of the l i cence

appl i cation is also important i .e. , whether to obtain the l icences on behalf of

the concessionaires prior to the procurement process or whether to al locate

thi s responsibi l i ty to individual concessionaires wi th commitment to

faci l i tate the speedy and unencumbered grant of the l i cences by the

Minister.

The Nigerian E lectricity Regulatory Commission

As previously stated, no electri city undertaking including commercial power

generation may be embarked upon without obtaining the relevant l i cence

from NERC. The FMOP would need to consider at what stage of the Project it

would ini tiate di scussions wi th NERC for the grant of generation l icence to

the investors. It may be preferable for the purpose of certainty to initiate

thi s process concurrently wi th the appl ication of permit f rom the River

Basins Authori ties. This would give investors more confidence in the Project.

It would al so aid in negotiating at an early stage, relevant l i cence terms and

conditions such as the duration of the l icence and renewal period and other

l icensing requirements. The type of generation l i cence to be obtained would

also need to be properly considered i .e. , whether the investors should

operate as embedded generators, whether the generated power would be

suppl ied to el igible customers as provided for in the EPSRA or other pre-

determined electri city consumers.

16. Conclusion and Recommendations on Feasibility Assessment

On the basis of the technical and financial feasibility assessment the following conclusions

and recommendations can be drawn:

1) The Omi dam appeared to be sound structurally; nevertheless it called for better

maintenance of the various structures of the dam in general.

2) The hydrology of the reservoir needs to be studied thoroughly using daily inflow

data.

3) The dam was initially constructed to primarily cater to the irrigation demands for

irrigating 8000 Ha of land. However it was noted that no substantial cultivation was

being carried out in the irrigated area. Also the discharge from the dam was not

being controlled or monitored. This clearly indicates that the waters stored in the

Omi dam can be put to better use such as that of power generation. To utilize the

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potential energy in the stored waters of the OMI dam, detailed hydrological and

topographical studies should be conducted for the sizing of the project and the

placement of the appurtenant structures of the project. In addition, The need for the

irrigation, domestic household purpose, ecological release should be monitored and

estimated to calculate the power generation potential of the dam more accurately.

4) Based on the assumptions made and the data shared in the reports, the dam can

support either hydro power plant or irrigation demand, domestic/industrial

demmand and other associated works. The elevation difference of ~16m between

the irrigation canal and the tail water level of the proposed Hydro power project

make the two schemes mutually exclusive.

5) If hydro power plant is considered then based on the assumptions stated above the

optimum capacity will be of 2 MW with 48.55% plant load factor. The annual energy

generation is approximately 8.51 GWh with 4,687 hours of operation annually.

However a thorough study with detailed flow / discharge analysis needs to be

conducted to firm up these numbers.

6) A wing wall is recommended for safe guarding the powerhouse civil structures and

E&M equipment in case of flood. The elevation of the powerhouse elevation is ~218

m whereas the Tail water level is 209 m. The highest flood discharge is 3550 cumecs.

In order to block this discharge of 3550 m3/sec, a suitably designed wing wall has

been proposed to be contructed. The reach of the flood discharge needs to be

ascertained to analyse the effectiveness of the wingwall.

Conclusion from the financial sensitivity analysis results

7) The sensitivity analysis confirms the fact that the project has a certain cushion to

absorb the negative impact of critical input variables such as higher capital cost,

lower generation, higher operating costs etc.

8) Even if the capital cost increases by 10%, the levelized cost of generation of power at

10.96 US c/KWh is well below the levelized tariff (19.04 US c/KWh). Even when the

project power generation is reduced by 10%, the minimum DSCR at 1.49x is higher

than the target DSCR of 1.40x. The lowest IRR value for private participant is

observed in combined case B (Case 17) at 20.70%.

Thus it can be concluded that the project is financially viable and has enough room to

absorb variations in assumptions.

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Part B: Structuring of the Project

17. Risk Assessment and Allocation80

The structuring of project risk is an important part of any PPP project. The identification,

analysis, mitigation and allocation of risk are crucial to the planning and success of every

project. After critical risk areas are identified, their impact on different project parameters

can be analysed. This helps in prioritizing and structuring the mitigation process and

increasing the probability of success of the project.

The primary principles of risk allocation are as follows:

a. Risk should be allocated, by contract or otherwise, to the party best able to mitigate

or control such risk.

b. Economic benefits should be adjusted in relation to the risks assumed.

c. The return on investment to the private investor should be in consonance with the

risk assumed by them.

d. Financial responsibility for project risks should be allocated to the project parties

based on their credit worthiness and the willingness to assume the risk.

e. Certain risks which cannot be controlled or mitigated may not be attributable to any

party. Such risks can cause a loss to the private party’s investment.

Example in line with the above mentioned principles are:

I. Contractors to the project should be expected to accept risks which are linked to the

construction of the project facilities.

II. The operator should be expected to accept risks which are linked to the operation of

the project.

III. Government or Public participants should be expected to accept risks related to

regulatory environment and local laws.

Generally project risks are shared between the lenders and the Equity investors in the

proportion of their respective investment / exposure. Project sponsors are expected to bear

performance risks (which are in part transferred to contractors, suppliers and/ or

operators).

Typically, host governments / the Public Participant are willing to accept political risks in the

host country, which include, for example,

Legislative changes

Failures and interference of host government authorities

Currency inconvertibility

General strikes and other non-project-specific labor related interferences

Political unrest

War and similar events involving the host country

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Host governments do not normally accept the financial risks of a project unless this is a

requisite to a defined extent. This is done usually to make the project viable from the

perspective of the lenders and the equity investors or to address other public policy

objectives of the host government. Financial risks burden the economy and finances of the

host country and also create contingent liabilities for the future. Governments therefore

steer clear of assuming financial risks or providing financial/ sovereign guarantees to back

the investments.

To some extent, risks can be covered by having adequate insurance available at a

reasonable cost. Insurance is a commonly used instrument for covering the insurable risks,

with the cost of insurance being included in the project’s pricing.

The individual perspective on risk allocation varies from participant to participant depending

upon their technical and financial position and their ability to evaluate, understand and

mitigate the posed risk. Hence different parties in a PPP often negotiate differently on the

allocation and incidence of identified risks. Negotiations are settled based on a risk vs.

reward trade off.

PPP documentation often involves a Risk Matrix - a common tool in a tabular format, which

compares the degree of incidence of various risks for all the PPP participants. The Risk

Matrix allows the participants to understand various risks and their effect on the project.

Mitigation measures for each risk and the allocation of risks to specific participants is also

dealt with in the Risk Matrix. Another important factor analyzed in the risk matrix is the

impact and consequences of the risk for parties to whom the risks have been assigned and

to those who do not bear the particular risk.

A typical risk matrix for a PPP transaction is shared in the forthcoming section81. The risks are

also described in detail in the next section.

Categorization of risks

One of the founding pillars of the concession agreement is the categorization of the

identified project risks. Once risks are categorized, they can be evaluated and their impacts

can be estimated. Project financing also depends heavily on highly structured assumptions

and the allocation of risks to the entities involved in the project.

Some of the common categories of commercial risks involved in a PPP project are described

below.

17.1. Construction and completion risks:

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Cost overruns and delays in performance are the most important and common risks

associated with the construction period. The responsibility of project engineering

design often lies with the private participant (Project Company), which in turn

transfers the responsibility and risk to the contractor, under an EPC agreement

containing back-to-back obligations, usually for a fixed price. Most of the

construction risk (if not all) lies with the project company and not with the

government. The project company may abstain from assuming the risks that relate

to political uncertainty or country level risks. The private participant will also be

averse to assuming any kind of risk where it does not have the opportunity to

conduct a thorough due diligence of the project. As the private participant has the

responsibility to execute the design and construction of the project, it is in the best

position to assume the risk for the same as well.

17.2. Developer Risk

This is important from the point of view of the FGN, especially when the project is

being planned on Public Private Partnership (PPP) Basis. FGN would like to ensure

that the Private Participant selected as Developer for the project is financially &

technically capable of successfully executing the project. If the Developer is not

qualified or capable, the project may fail to get commissioned on time or within

budget. This can adversely impact the financial return of the public participant (FGN)

and/or result in sub-optimal results from the project.

Developer risk can be mitigated through the following measures:

Devise a concession process that weeds out weak Developers

Identify selection criteria based on technical and financial capabilities of

project developers that result in selection of capable project developer/

investor

Robust concession agreement having equitable distribution of responsibilities

Checks & Balances incorporated into the process; Reporting requirements all

through the project development, construction and concession periods

17.3. Operating risks:

The concession period for the proposed hydro power project at OMI dam is likely to

be a long term contract. The operating costs for the project over the term of the

concession period may be difficult to estimate without thorough understanding of

the project components, their wear and tear, maintenance requirements and

general levels of inflation in Nigeria. In general there are two ways of dealing with

this issue:

The Public Participant could allow the project company to pass the increased

input costs on to the consumers of the electricity generated. The escalation

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could be pre-determined based on local inflation rate (CPI or WPI) for local

expenses and foreign inflation (US CPI) for costs denominated in foreign

currency.

The project company could mitigate the input risks by entering into long-term

supply agreements with reliable suppliers (although this means the project

would not benefit from downward trends in costs).

Example: Volatility of input costs (labor costs) and technology changes.

17.4. Demand, Power off-take and price risks:

Hydroelectric Projects are highly dependent on the revenue paid by the public utility.

Usually the private participant would bear this risk, but would insist on some

measures from the government to mitigate the risks.

Power off-take risk is the risk that the project is not able to sell the entire quantum

of power that it generates or could potentially generate in any given period of time.

Power off-take risk is a revenue risk – if the project is not able to sell power, it loses

out on the revenue associated with it, unless there are provisions in the PPA to take

care of such situations.

The inability to sell power could be because of various reasons. One of the reasons

could be the lack of demand from the customers of the power purchaser. E.g. there

could be particular periods of the day during which power demand is lower and

hence the power purchaser gives back-down instructions to the power plant.

Another reason is the unavailability of the transmission or distribution network due

to faults or maintenance works. If the transmission/ distribution network is down,

purchaser will not be able to off-take power even though the power plant is

available. In some cases, the off-taker may not have funds to pay for the power and

hence may decide to reduce power off-take from the power plant. Thus, the financial

strength of the power purchaser is one of the important indicators for the mitigation

of this risk.

Power off-take risk would result in reduced revenues for the project, and hence

reduce the financial returns to the project promoters. This may also result in lower

debt coverage ratios and in extreme cases, the project may have problems in making

the interest and principal payment as per schedule.

A typical mitigation measure would be inclusion of ‘take or pay’ or ‘deemed

generation’ clauses in the PPA. Deemed energy generation means that the project

would be deemed (or assumed) to have produced and sold electricity in case the

power plant is required to reduce or stop generation for a reason beyond its control

– such as lack of demand or fault in the transmission/ distribution network. The PPA

obligation of the utility could also be supported by a federal government support

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letter. The price risk is taken care of by a fair and pre-determined tariff structure, in

this case the MYTO II tariff mechanism.

The off-taker payment risk can be reduced by signing the PPA with a financially

sound off-taker. Finally, the transmission and distribution networks should be

maintained in good condition and downtime should be reduced with preventive

maintenance. The loss of revenue can in some cases be protected through insurance.

17.5. Technology risks:

There are two main types of risks associated with technology.

Latent defects in the technology used in the project would affect the

performance of the project in the long run.

Developments in technology may make the technology used in the

project obsolete. This might also result in services delivered from projects

based on old technology becoming inefficient or uncompetitive.

In case of the mini hydro power project, this risk is low as the technology for

electricity generation is very mature and well understood. No major innovations are

expected as the efficiencies of the current technology are quite high.

17.6. Change of law risks:

Changes in the governments’ laws over the course of time may adversely affect the

project company. As the changes of laws are within the control of the government,

the Public Participant should accept to bear the risk of adverse circumstances for the

project. The project company would be expected to be compensated for any

discriminatory changes in laws. However, it would be expected to bear the risk of

changes of law if these changes affect the project company’s competitors equally.

17.7. Environmental risks:

Generally, the Public participant is liable for pre-existing conditions of the land

where the Public participant has the obligation to provide the land to the project

company, and is often achieved through including warranties and indemnities.

After the transfer of possession of the facility / land to the project company, the

project company should be obliged to conduct the project in compliance with the

applicable environmental regulations. Noncompliance with applicable environmental

law and regulations lead to penalties as applicable under the Nigerian law, along

with the cost of the clean-up required.

17.8. Casualty risks:

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Casualties and mishaps are always a possibility on infrastructure construction sites.

They should be insured against.

17.9. Ownership and Borrower risks:

The sponsors / share holders of the project would not want the creditors and lenders

to the project to have recourse to their assets outside the project company. It is

therefore prudent to ring-fence the project company and its assets that are pledged

as security for supporting the borrowing.

17.10. Property and contingent liabilities:

This refers to protection of property ownership, risk of expropriation by the

government or a public authority and compensation in case of expropriation to the

private participant.

17.11. Country and political risk:

The project is affected by the civil and political stability of a country e.g. strikes, civil

strife, coup etc.

17.12. Counterparty credit risk:

To minimize the counterparty credit risk the Public Participant needs to ensure that

only reputed and the credit-worthy private participants are selected for the PPP

project. If the counterparty is a newly incorporated special purpose vehicle,

undertakings or guarantees from the parent organizations/ shareholders should be

taken and their credit-worthiness should be assessed.

17.13. Exchange rate risks:

Generally the revenues earned in providing infrastructure services are in the local

currency. As most overseas sponsors / equity investors report their earnings in a

different currency, the earnings of the project company may get distorted due to the

exchange rate fluctuations.

The principal and interest payment obligations for project finance may be in a

different currency. Depreciation in the value of the local currency may make it

difficult to repay the loan and may lead to default on the loan repayment

obligations.

Exchange risks can be managed through hedging by purchasing forward contracts

equivalent to the estimated outgo of foreign exchange. At times, the payment for

services or a part thereof can be denominated in the foreign currency of choice for

the lenders/ private participant.

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17.14. Interest rate risks:

Usually, international lenders provide finance on the basis of the cost of risk free

capital (usually LIBOR) plus a mark-up margin (lender’s perception of the market

risks). As a result, the project company may be exposed to the risk of a general rise

in interest rates. The Public Participant needs to consider whether this rise in

interest rate could indirectly be passed on to the customers (for example, as an

adjustment to tariffs due to increase in debt servicing expenses). Generally, interest

rate swaps are available at a price and allow the borrower to fix the interest rate for

the entire loan repayment period.

17.15. Hydrology Risk

The most important factor to be considered while developing a hydro power project

is the availability of fuel i.e. water. Hydrology risk is the risk that the actual quantum

of water available for power generation is less than what was assumed during

planning stages. This means that the power generation would be lower as compared

to that estimated during planning. This risk thus directly impacts the power

generation and hence the revenue generation of the project.

Hydrology i.e. availability of water in a hydro power project varies as per the season

of the year (dry vs. wet or rainy season). Availability of water may also vary from

year to year, depending on the precipitation (rains) in that particular year (e.g. flood

vs. drought year). Thus, accurate prediction of exact amount of water available in

any hydro power project at any point of time is not possible. This introduces an

inherent uncertainty in the hydrology analysis of a planned project as it involves

prediction of water availability in the future years. This problem is tackled by

conducting a statistical analysis of existing water flow and rainfall data to arrive at a

confidence interval. The accuracy of this prediction is improved if there a number of

data points are available and the data is reliable.

Another important thing to note is the project sizing. As the project size increases,

the project becomes more dependent on the hydrology data and the hydrology risk

increases. So project’s installed capacity (MW) should be carefully finalized so that

the power generation is optimum and there is a margin of safety in the project’s

financial returns.

The optimum installed capacity for the project has been arrived at as 2.0 MW, with

an annual plant load factor of 48.55%. The annual energy generation will be 8.51

GWh equivalent to 4,687 hours of annual operation.

However, it should be noted that the above calculation is based on very limited

hydrology data for the Omi dam. Water flow in and out of the dam should be gauged

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and data so collected should be subjected to hydrology analysis. Such data can

provide a more robust and accurate picture of the power potential for the Omi dam.

To obtain water flow and rain fall data, gauge stations need to be established on the

river (close to the intake point of the project) and the catchment area of the river

upstream of the intake. Though long term data is preferable, continuous data for at

least 18 months (covering dry seasons of two consecutive years) is a must.

17.16. Geological Risks & Surprises

Geological risks and surprises are not uncommon while constructing hydro power

projects due to the extensive civil works involved in construction of dams,

powerhouses & associated structures. For a dam based project, the geological risks

become critical due to safety considerations & the costs involved in overcoming

those risks.

Comprehensive geological investigations should be carried out before commencing

construction of the project. Sub-Surface geological investigations and tests should be

carried out to determine soil characteristics, rock foundation, load bearing capacity,

compressibility etc. at 2/3 different powerhouse locations. The final location for the

powerhouse should be selected based on the results of the geological investigations.

Since the dam is already constructed and is in good condition, the geological risks are

reduced for this project. Investigations are required only for the powerhouse and

tailrace locations.

If geological conditions at the selected powerhouse locations are not found to be

good, the construction costs may increase as deeper excavation may be required

(e.g. if rock is not present) or foundation works may be more expensive.

17.17. Financing Risk

Financing risk is the risk that the developer is not able to arrange the required funds,

i.e. equity and debt, for the construction of the project. Arrangement of adequate

project finance is critical for the project as construction of the project requires timely

payments to contractors and suppliers. At times, due to certain unforeseen events,

cost overruns are encountered which may require additional funding sources.

Financing risk can be mitigated through the following measures:

- Selection of financially sound project developer through rigorous concession

process

- Use of robust Project Finance structures & documentation (e.g. Contractual

agreements such as Power Purchase Agreement (PPA) & Concession Agreement;

Project Finance documents such as loan facility agreement with Banks;

Watertight EPC contract with Contractor)

of 202

- Reliable estimates for project cost based on technical studies & negotiations with

Suppliers and Contractor

- Inclusion of adequate Contingency funds and standby lines of funding at the time

of Financial Closure.

17.18. Force Majeure conditions / Risks

Force Majeure conditions or risks are events that are beyond the control of the

project participants. Such events can be classified as a) Act of God – such as floods,

earthquakes, hurricanes etc. and b) Other events – such as war, arson, regime

change, policy change, etc.

Maintaining adequate and proper Insurance against such events is the only

mitigation possible.

Pa

ge

136

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

De

ve

lop

me

nt

pe

rio

d &

Co

nst

ruct

ion

Pe

rio

d R

isk

s

Co

st O

ve

rru

n

Within

Con

stru

ction

Con

sortium

Contr

ol

Incl

ud

ed

in F

ixe

d P

rice

Lum

p S

um

EP

C C

on

tra

ct

No

Eff

ect

N

o E

ffe

ct

O

utsid

e C

on

stru

ction

Con

sortium

Contr

ol:

- In

sure

d e

ven

t P

roce

ed

s o

f in

sura

nce

po

licy

incl

ud

ing

bu

sin

ess

inte

rru

pti

on

in

sura

nce

Dra

w o

n s

tan

db

y fi

na

nce

if i

nsu

ran

ce p

oli

cy

exh

aust

ed

;

De

bt

cove

rag

e r

ati

os

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

ero

de

d b

y

serv

icin

g o

f st

an

db

y

fin

ance

-Un

insu

red

fo

rce

ma

jeu

re

Dra

w o

n s

tan

db

y fi

nan

ce

De

bt

cove

rag

e r

ati

os

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

ero

de

d b

y

serv

icin

g o

f st

an

db

y

fin

ance

- G

rou

nd

co

nd

itio

ns

Dra

w o

n s

tan

db

y fi

na

nce

D

eb

t co

vera

ge

ra

tio

s

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

ero

de

d b

y

serv

icin

g o

f st

an

db

y

fin

ance

Pa

ge

137

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

- O

wn

er

var

iati

on

ord

ers

D

raw

on

sta

nd

by

fin

an

ce

an

d l

imit

sco

pe

of

var

iati

on

s b

y O

wn

er

De

bt

cove

r fa

cto

rs

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

ero

de

d b

y

serv

icin

g o

f st

an

db

y

fin

ance

- C

ha

ng

es

of

law

, de

lay

s in

ob

tain

ing

ap

pro

vals

or

pe

rmit

s, i

ncr

ea

sed

ta

xes

Sta

nd

by

fin

an

ce d

raw

n

pe

nd

ing

tari

ff a

dju

stm

en

t

De

bt

cove

rs f

act

ors

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

mig

ht

be

re

du

ced

be

cau

se o

f ti

min

g e

ffe

cts

De

lay

in C

om

ple

tio

n

Wit

hin

Co

nst

ruct

ion

Co

nso

rtiu

m C

on

tro

l

Liq

uid

ate

d D

am

ag

es/

Pe

na

ltie

s im

po

sed

on

th

e

con

tra

cto

r a

s p

er

the

EP

C

con

tra

ct t

erm

s.

(Su

ffic

ien

t to

co

ver

inte

rest

d

ue

to

Le

nd

ers

an

d f

ixe

d o

pe

rati

ng

co

sts)

De

bt

cove

r fa

cto

rs

red

uce

d,

if s

tan

db

y d

eb

t

dra

wn

No

e

ffe

ct

(exc

ep

t lo

ss o

f

op

po

rtu

nit

y to

e

arn

bo

nu

ses)

un

less

pe

na

ltie

s

full

y sp

en

t.

U

se

of

sta

nd

by

fin

an

ce

for

furt

he

r co

sts

wil

l e

rod

e

retu

rn

Pa

ge

138

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

Insu

red

Fo

rce

Ma

jeu

re

Pro

cee

ds

fro

m b

usi

ne

ss

inte

rru

pti

on

in

sura

nce

po

licy

Sta

nd

by

fin

an

ce d

raw

n i

f

insu

ran

ce p

oli

cy

exh

aust

ed

;

De

bt

cove

r fa

cto

rs

red

uce

d i

f st

and

by

de

bt

fin

ance

use

d

To

th

e e

xte

nt

tha

t th

e

ab

ilit

y to

pa

y d

ivid

en

ds

is

po

stp

on

ed

, re

turn

ma

y b

e

ero

de

d

Gro

un

d C

on

dit

ion

s D

raw

on

sta

nd

by

fin

an

ces

De

bt

cove

r fa

cto

rs

red

uce

d i

f st

and

by

de

bt

fin

ance

use

d

Re

turn

ero

de

d b

y

serv

icin

g o

f st

an

db

y

fin

ance

Fai

lure

of P

lan

t to

me

et

Pe

rfo

rma

nce

Spe

cifi

cati

on

s a

t

Co

mp

leti

on

Te

sts

as

a

resu

lt o

f fa

ult

by

Co

nst

ruct

ion

Co

nso

rtiu

m

Ca

pa

city

sh

ort

fall

P

en

alt

ies

pay

able

by

Co

nst

ruct

ion

Co

nso

rtiu

m

sup

ple

me

nte

d b

y

insu

ran

ce

If c

ap

aci

ty s

ho

rtfa

ll is

sig

nif

ican

t, D

eb

t co

ve

rag

e

rati

os

ma

y b

e r

ed

uce

d

fro

m b

ase

ca

se le

vels

.

Oth

erw

ise

, n

o e

ffe

ct.

Re

turn

re

du

ced

if

pe

na

ltie

s fr

om

Co

nst

ruct

ion

Co

nso

rtiu

m

exh

aust

ed

. A

lso

, if

cap

aci

ty s

ho

rtfa

ll i

s

sig

nif

ican

t, r

eve

nu

e

ge

ne

rati

on

fro

m t

he

pro

ject

ma

y b

e r

ed

uce

d.

Pa

ge

139

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

Op

era

tin

g C

ost

s O

ve

rru

n

Co

sts

exc

ee

d o

rig

ina

l

est

ima

tes,

No

t an

insu

ran

ce o

r Fo

rce

Ma

jeu

re e

ven

t

Sta

nd

by

fin

an

ce d

raw

n

De

bt

cove

r fa

cto

rs

red

uce

d i

f st

and

by

de

bt

use

d

Re

turn

re

du

ced

by

serv

icin

g o

f st

an

db

y

fin

ance

Insu

ran

ce c

ost

s e

xce

ed

ori

gin

al

est

ima

tes

Sta

nd

by

fin

an

ce d

raw

n

pe

nd

ing

Ta

riff

ad

just

me

nt

De

bt

cove

r fa

cto

rs s

lig

htl

y

red

uce

d d

ep

en

din

g o

n

tim

ing

eff

ect

Re

turn

ma

y b

e r

ed

uce

d.

Inve

sto

rs m

ay

be

fo

rce

d

to i

nv

est

hig

he

r e

qu

ity

am

ou

nts

to

co

mp

en

sate

for

hig

he

r co

sts.

Incr

ea

sed

Fin

anci

ng

Co

sts

Inte

rest

ra

te in

cre

ase

S

tan

db

y fi

na

nce

dra

wn

pe

nd

ing

Ta

riff

re

op

en

er

De

bt

cove

r fa

cto

rs s

lig

htl

y

red

uce

d d

ep

en

din

g o

n

tim

ing

eff

ect

Re

turn

ma

y b

e r

ed

uce

d.

Inve

sto

rs m

ay

be

fo

rce

d

to i

nv

est

hig

he

r e

qu

ity

am

ou

nts

to

co

mp

en

sate

for

hig

he

r co

sts.

Pa

ge

140

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

Ad

vers

e e

xch

an

ge

ra

te

flu

ctu

ati

on

s

Sta

nd

by

fin

an

ce d

raw

n

pe

nd

ing

tari

ff r

eo

pe

ne

r

De

bt

cove

r fa

cto

rs s

lig

htl

y

red

uce

d d

ep

en

din

g o

n

tim

ing

eff

ect

Re

turn

ma

y b

e r

ed

uce

d,

if

the

ta

riff

is

no

t

de

no

min

ate

d in

th

e

fore

ign

cu

rre

ncy

of

cho

ice

, o

r if

he

dg

ing

do

es

no

t co

ve

r e

nti

re f

ore

ign

curr

en

cy c

om

po

ne

nt

of

rev

en

ue

.

Ad

vers

e c

han

ge

s in

te

rms

of

fin

ance

Sta

nd

by

fin

an

ce d

raw

n

pe

nd

ing

tari

ff r

eo

pe

ne

r

De

bt

cove

r fa

cto

rs s

lig

htl

y

red

uce

d d

ep

en

din

g o

n

tim

ing

eff

ect

Re

turn

ma

y b

e r

ed

uce

d.

Inve

sto

rs m

ay

be

fo

rce

d

to i

nv

est

hig

he

r e

qu

ity

am

ou

nts

to

co

mp

en

sate

for

hig

he

r co

sts.

Pa

ge

141

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

Go

vern

me

nt

Min

or

cha

ng

es

in t

ax,

law

,

cust

om

s, l

eg

al

req

uir

em

en

ts,

en

viro

nm

en

tal s

tan

dar

ds

Ta

riff

ad

just

me

nt

(if

du

rin

g c

on

stru

ctio

n

pe

rio

d,

sta

nd

by

fin

an

ce

dra

wn

)

Sta

nd

by

fin

an

ce c

ou

ld b

e

req

uir

ed

.

No

eff

ect

on

De

bt

Se

rvic

e

Co

ver

Fa

cto

r

No

eff

ect

, a

s lo

ng

as

the

cha

ng

es

are

pa

ss-t

hro

ug

h

in t

he

co

nce

ssio

n

ag

ree

me

nt.

Exp

rop

ria

tio

n,

na

tio

na

liza

tio

n,

con

sen

ts

wit

hd

raw

n,

inte

rfe

ren

ce

cau

sin

g s

eve

re p

reju

dic

e

Ow

ne

r e

nti

tle

d t

o

term

inat

e a

s G

ov

ern

me

nt

de

fau

lt

If o

wn

er

term

ina

tes,

lo

an

rep

aid

or

ass

um

ed

as

com

pe

nsa

tio

n

If G

ov

ern

me

nt

de

fau

lts

an

d o

wn

er

term

ina

tes,

com

pe

nsa

tio

n p

aid

fo

r

term

inat

ion

Fun

da

me

nta

l b

rea

ch b

y

the

Go

vern

me

nt,

un

de

r

ag

ree

me

nts

Ow

ne

r e

nti

tle

d t

o

term

inat

e a

s G

ov

ern

me

nt

de

fau

lt

If o

wn

er

term

ina

tes,

lo

an

rep

aid

or

ass

um

ed

as

Co

mp

en

sati

on

If G

ov

ern

me

nt

de

fau

lts

an

d o

wn

er

term

ina

tes,

com

pe

nsa

tio

n p

aid

fo

r

term

inat

ion

OPE

RA

TIO

N PERIO

D

Op

era

tin

g C

ost

s O

ve

rru

n

As

a r

esu

lt o

f ch

ang

es

in

reg

ula

tio

ns

Ta

riff

ad

just

me

nt

No

eff

ect

N

o e

ffe

ct

At

Ow

ne

r’s

req

ue

st

No

ad

just

me

nt

to T

ari

ff

De

bt

cove

r fa

cto

rs

red

uce

d

Re

turn

re

du

ced

Pa

ge

142

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

As

a r

esu

lt o

f fa

ilu

re b

y

the

op

era

tor

No

ad

just

me

nt

to T

ari

ff.

Pe

na

ltie

s p

ayab

le b

y th

e

op

era

tor

De

bt

cove

r fa

cto

rs

red

uce

d i

f p

en

alt

ies

exh

aust

ed

Re

turn

re

du

ced

if

pe

na

ltie

s e

xhau

ste

d

Infl

ati

on

, Ad

ve

rse

Ch

ang

es

in C

ost

of

Fin

an

ce,

Exc

han

ge

or

Inte

rest

Ra

te R

ate

s

Ma

cro

eco

no

mic

fa

cto

rs i

n

the

lo

cal

an

d g

lob

al

eco

no

mie

s

Ta

riff

ad

just

ed

by

ind

ice

s.

Sm

all

po

ssib

ilit

y th

at

mo

ve

me

nts

in in

dic

es

do

no

t e

xact

ly m

atc

h

cha

ng

es

in a

ctu

al

cost

s

De

bt

cove

r fa

cto

rs c

ou

ld

be

re

du

ced

Po

ssib

ilit

y o

f e

rosi

on

in

retu

rn

Fore

ign

Exc

han

ge

No

n-

Ava

ila

bil

ity/

No

n-

Co

nv

ert

ibil

ity

Du

e t

o la

ck o

f li

qu

idit

y in

loca

l cu

rre

ncy

ma

rke

ts o

r

du

e t

o G

ove

rnm

en

t

rest

rict

ion

on

cu

rre

ncy

con

vert

ibil

ity

Go

vern

me

nt

gu

ara

nte

es

ava

ila

bil

ity

of

fore

ign

exc

ha

ng

e.

If

Go

vern

me

nt

de

fau

lts,

Ow

ne

r ca

n

term

inat

e

Loa

n r

ep

aid

or

ass

um

ed

as

Co

mp

en

sati

on

No

eff

ect

(e

xce

pt

loss

of

op

po

rtu

nit

y to

ea

rn

bo

nu

ses)

if

Go

vern

me

nt

pa

ys u

nd

er

guar

an

tee

. I

f

Go

vern

me

nt

de

fau

lts

un

de

r gu

ara

nte

e a

nd

Ow

ne

r te

rmin

ate

s

Co

mp

en

sati

on

pa

id f

or

term

inat

ion

Fai

lure

to

Ma

ke A

vail

ab

le

Suff

icie

nt

Fore

ign

Exc

ha

ng

e

Go

vern

me

nt

de

fau

lt

Ow

ne

r ca

n t

erm

ina

te

If O

wn

er

term

ina

tes,

loa

n

is r

ep

aid

th

rou

gh

Co

mp

en

sati

on

Co

mp

en

sati

on

pa

id f

or

term

inat

ion

Pa

ge

143

of 202

RIS

K M

ITIG

ATIO

N A

NALYSIS

RIS

K

RE

AS

ON

RE

ME

DY

C

ONSE

QUE

NCES

FO

R

LE

NDE

RS

CO

NSE

QUE

NCES

FO

R

INVES

TO

RS

Fai

lure

of

pu

rch

ase

r o

f

po

we

r (S

tate

ow

ne

d

uti

lity

) to

Pe

rfo

rm

Ob

lig

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of 202

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18. Key Commercial Principles and Payment Mechanisms

The PPP arrangement will be based on a number of contractual agreements between the

concerned parties such as Public participant, Private participant, financing institutions, EPC

contractors, & Operators among others. The following chart contains an overview of the

contractual structure of a typical PPP project. Each of the boxes represents participating

entities & the arrows represent transactional relationships among these entities.

Image 1: Overview of project agreements

The various agreements have been categorized as follows:

I. Agreements Between the Government and their consultants: Retainer

II. Agreement Between the Government and the Project Company for granting the right

to operate the power project: Concession Agreement

III. Agreement Between the Sponsors and the Project Company to provide equity

finance to the project: Equity Finance/ Share Subscription Agreement/ Share

Holders Agreement

IV. Agreements Between the Lenders and the Project Company to provide debt finance

to the project: Financing documents/ Facilities agreement

Government (Public Participant)

Public

Participant

Consultant

Concession

agreement

Retainer

Sub Debt

Agreement Shares

Sponsor

(Private Participant) [Shareholders’ Agreement]

Performanc

e Guarantee

Options

Agreement

Project Company

Loan

Lender [Intercreditor

Agreement]

Security

Documents

Contractor EPC

Operator O&M

Agreement

Supplier Supply

Agreemen

Supply

Agreement

Supply

Agreement

Bond Holder [Trustee Appointment

Agreement]

T&C of

Bonds

Bonds

Customer

Off-take

agreement

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V. Agreements Between the Bond-Holder and the Project Company provide quasi-

equity finance to the project through issuing securities such as bonds: Quasi-equity

Finance

VI. Agreements to design, construct, operate and maintain the Hydro power Project:

Design, Construct, Operate and Maintain / EPC contract/ O&M contract

VII. The agreements with customers of the power project (Power Purchase Agreement):

Off-take agreements/ PPA

Each of the above mentioned agreements are described in detail in the following sections. A

subsection titled “Points to be noted by the Public Participant” describes the critical factors

to be addressed by the Government/ Public Participant to ensure that the primary

objectives and concerns of the government/ public participant with respect to the PPP

project are addressed adequately.

Another subsection titled “Key pointers for the Private Participant” includes issues of

critical importance for the Private Participant. These critical issues are often heavily

negotiated. It is important to consider all project agreements as a whole because all

agreements are interdependent & need to be drafted in a holistic manner.

18.1. Retainer

This section deals with the agreement between the government and its consultants82

. The

Public Participant usually needs to retain consultants to conduct a PPP project. The

consultants design the PPP structure, help in drafting the PPP contractual documents and

conduct the PPP award process from start to finish. Typically, a number of consultants from

different domains such as technical, legal, financial may be involved.

18.1.1. Points to be noted by the Public Participant

The Public participant’s main objectives for their contractual agreement with consultants

are:

a. Quality. The Public Participants must hire consultants of repute, who have the

experience & qualifications of having delivered similar projects in the past. A number

of qualifying factors need to be addressed in the retainer that could contribute to

better quality advice.

b. Terms of Reference or ToR. A retainer agreement should contain clearly defined

“Terms of Reference” (TOR) which outline the scope of work and the process of

delivery of the work by the consultants. The TOR should also contain the timelines

for delivery of various milestones for the work.

82

Source: http://rru.worldbank.org/Documents/Toolkits/hiringadvisors_fulltoolkit.pdf ,

http://www.unescap.org/ttdw/ppp/trainingmaterials/PPPs_Legal_Perspective.pdf, Retrieved on 26 August 2013

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c. Incentives. To align the mutual interest of the consultants with that of the client,

mechanisms or incentives such as “Success Fee” based compensation should be

devised.

d. Assessment. A mechanism for continually / periodically assessing the consultants’

performance should be incorporated in the retainer agreement. Steps for resolving

all disputes arising on the basis of the review and assessment should be outlined.

The Public participant should refrain from terminating the contracts in haste as it

may lead to delays, litigation, additional costs and loss of trust in the private sector.

e. Cost. The public participant should look for value for money instead of absolute

cost. Although the fees charged by the Consultants add to the overall costs, a

properly designed and well-conducted PPP process will result in much larger gains

for the Public Participant. The public participant should steer clear of the following:

Conflicting instructions

Lack of commitment and

Lack of leadership support

These factors can cause delays and ultimately add to the cost of the PPP project. The

public participant should retain experienced and reputable consultants at market

prices instead of going for the least cost option.

f. Trust. The consultant and the public participant should share a relationship of trust.

Generally in most common law jurisdictions, fiduciary obligations extend even

beyond the express terms of the contract. However, a retainer must clearly impose

contractual obligations of confidentiality and provide for ways to resolve conflict of

interest situations.

18.1.2. Key takes for the Retainer agreement:

The first agreement entered into by the government in relation to a PPP project is a

retainer. It is the agreement between the Public Participant and their consultants governing

the terms & conditions under which the Public Participant’s consultants will deliver their

services.

Steps in executing a retainer document:

Step I: The document in the form of a letter is drafted by the Public Participant Consultants

containing the agreed upon terms and conditions and shared with the Public Participant in

duplicate.

Step II: The Public Participant reviews the draft agreement and suggests modifications

where necessary. The two parties negotiate and agree to the final draft of the agreement.

Step III: The Public Participant & the Consultants execute the agreement in at least two

counterparts, and keep a copy of the executed agreement.

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18.1.3. Major Concerns

A retainer should address the following concerns:

a. Fees:

The consultants’ fees may be of the following types:

Image 2: Types of Retainer Fees

Fixed fee. As the name suggests, a fixed fee is a lump sum amount. Although it has

clarity in definition of the amount payable, it suffers from the following limitations:

- Time factor: It may be difficult to estimate the time required for the

transaction in advance. Also, the transaction may be prolonged because

of certain external or internal issues and thus, the time input of the

consultants may be unpredictable at the start.

- Resource Allocation: As the job progresses, the resources needed by the

consultant to complete the project may change.

Usually a fixed fee component is in addition to other variable costs, for example, cost-plus-

fixed-fee basis.

Time based: Time based fees are the most common type of retainer fees. It entails the

payment of a “recurring fixed amount” or an “out of pocket expenses” + “profit

element” on an agreed time schedule; on the basis of hours, days or months.

Time based fees may have a collar i.e. a minimum amount payable (if the allocated work

is completed earlier) or a cap (if the allocated work takes more than the expected time).

Many a times the time based fee payable is “staggered”, varying over the time frame.

This is a midway approach between imposing a cap (usually not accepted by the

consultants) and paying retainer fees without a time limit (usually not accepted by the

Public participants).

Right at the beginning of the negotiations for the Retainer agreement, a “ballpark” or an

“estimate” for the cost of works should be calculated based on the scope of work and

nature of the project. The estimate should be agreed upon by both the parties. This

exercise gives the government an understanding of the consultants’ fees and helps in

negotiating a reduction of the actual fees. The parties may be able to change their

practices for greater efficiency in the future.

Types of Retainer Fees

Fixed Fees Time based Fees Percentage of

Transaction value Success Fee

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Percentage of Transaction value. This type of fees are payable as percentage of the total

transaction value. While this is common in financial advisory in mergers and acquisitions,

initial public offerings transactions and bonds issues, it is unusual in a typical PPP

project.

Success fee. This is an incentive based fee. It aligns the interest of the Public

participant’s consultant with its own, towards the successful completion of the project.

The “success fees” payable on the “completion” of the project is incorporated into the

contract by clearly defining success and completion. This type of fee arrangement is

common with legal and financial consultants “completion” means a financial close of a

transaction (in contrast to the completion of the infrastructure asset).

In any case, the fee structure and the amount of fees can be negotiated based on a

competitive process, wherein proposals from multiple qualified consulting organizations are

called and compared. Negotiations can then be conducted on the basis of the proposals to

arrive at the preferred consultant along with their fee structures.

b. Scope of work:

The Retainer agreement should clearly outline the scope of work. The Public participant

should ensure that the scope of work is consistent with the government’s understanding of

the consultant’s role in the project and the public participant’s expectations from the PPP

process.

c. Confidentiality:

Strict confidentiality should be maintained by the consultants with regards to all the data,

documents and information shared by the Pubic Participants. The following should be

ensured:

That confidential information is appropriately defined.

That the consultant does not use the confidential information for any purpose other

than to advise the government.

That the obligation extends to all sub-contractors, employees and agents of the

consultants. And,

That the government be notified if there is any breach of confidence.

d. Conflict of interest:

The Public Participant Consultants should not have clients whose interest’s conflict with

those of the Public participant. The market for PPP project consultants is highly specialized

and only a handful of suitably experienced and qualified consultants may be available. Thus,

there often arises a probability of conflicting interest which may be detrimental to the fair

conduct of the PPP process. It should be mentioned in the contract that the government

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should be informed of any conflict of interest as soon as the consultant becomes aware of

the same.

e. Professional liability:

In the event of any negligence in advice or impartment of wrong advice on the part of the

consultants, the consultants are liable to compensate the public participants. The

consultants may attempt to limit the extent of their potential liability. The public Participant

should review the scope and the exceptions (or “carve outs”) to the consultant’s liability.

The rationality of the exemptions from liabilities should be reasoned. A generic disclaimer

of liabilities for any advice or conduct of the consultant should not be acceptable, e.g., a

consultant should be liable for any fraudulent act of it, its employees or its agents. Also, a

specific exclusion of liability against, for example, losses in profits that failed to be realized,

usually referred to as “expectation losses”, is arguably acceptable.

f. Termination:

The Public participant should ensure that it is able to terminate the services of the

consultant if it is dissatisfied with the consultant’s services. Ideally, the government should

be able to terminate the consultant’s services at its discretion.

Either party could be allowed to terminate the retainer with notice to the other party

(though there may be a period of notice). However the level of termination rights may not

be the same for both the parties. E.g. in case of a success fee, the public participant should

not be able to terminate the retainer immediately prior to the completion of the project to

avoid paying the success fee.

g. Procedures:

The Public participant and the consultant should outline a process by which the Public

participant and its consultants would conduct the project and the procedures by which the

Public participant would review and asses the progress of the consultant’s work.

18.2. The Concession agreement:

The concession arrangement between the public and the private participants is the most

important & central agreement / document of the Public Private Partnership arrangement.

In PPP projects, a concession agreement supports the whole structure of the PPP

transaction. The key purposes of concession agreement are:

To define the working relationship between the public and the private

sectors.

To identify and allocate vital responsibilities & risks in the project.

To act as the central core of the security documentation for lenders.

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It is a guideline agreement between a project company and the relevant Public Participant

authority whereby the project company undertakes to construct and operate the particular

infrastructure or service. It also deals with the performance guarantee to the government

provided by the private participant. This is in effect a guarantee by a sponsor (usually from

the private sector) of the performance by the project company.

‘Concession agreement’ for all further discussions in the present context will refer to

contractual arrangements that give the private participant a right to operate the concerned

Hydro power project. Depending on what PPP structure is adopted, such agreement may

also be called a BOT agreement, BOOT agreement, a lease or a license.

On the basis of a bid, the government grants the project company the right to use and

receive the economic benefits arising from provision of the infrastructure services. The

ownership of the Hydro power project may be transferred to the government on

completion of a certain specified term, also known as the concession period.

18.2.1. Nature of the concession agreement:

It is generally assumed that the Public Participant in the PPP has entered into a concession

agreement in its commercial capacity, and contractual rights and obligations under the

concession agreement apply to the Public Participant no differently than to other

contracting persons.

Under the event of this assumption not being true, the parties will need to consider the

extent to which this changes the commercial rights of the project company. The project

company, its sponsors and its lenders, may have concerns about irrevocability, certainty and

enforceability of their rights that need to be addressed. An enabling legislation may need to

be enacted to overcome these concerns.83

The concession agreement cannot be considered in isolation from the regulatory and

legislative environment of the project area.

18.2.2. Main objectives of the Public Participant in the concession agreement

The main objectives of the Public Participants in a concession agreement are as follows:

18.2.2.1. Successful construction of the Hydro power project:

Under the PPP arrangement, the design, financing and construction of the Hydro power

project may be undertaken by the private participant. One of the main objectives of the

concession agreement is to ensure correct and optimum design as well as construction of

the hydro power project, achieving the objective set out by the Public Participant in a timely

manner. The Private participant alone should be responsible for any fault in the design and

83

Source: United Nations Commission on International Trade Law (UNCITRAL), Model Legislative Provisions on

Privately Financed Infrastructure Projects, 2004.

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construction of the Hydro power project (except in the limited circumstances that the defect

or delays were caused by the Public Participant).

18.2.2.2. Quality of construction of the hydro power project

The concession agreement should outline the basic standards and guidelines of quality that

should followed and achieved in the construction of the hydro power project. The

responsibilities of the private participant should be clearly defined as well.

18.2.2.3. Electricity generation:

The Public Participant should articulate its needs and expectations of the private participant

in clear and quantifiable terms with regards to the expected generation. The project

company should provide the minimum or expected generation throughout the period of the

concession. Properly defining the responsibilities of the private sector is the key to

successful implementation of the project.

18.2.2.4. Revenue and electricity sharing with various related entities (e.g.

Hydroelectric Power Producing Areas Development Commission):

The concession agreement should clearly mention the services or the revenue / electricity

sharing that the project company will have to provide to the local area; for example:

Revenue shared With Hydroelectric Power Producing Areas Development

Commission

Free power to be given for electrification of the local area.

Revenue sharing with the State/ Federal Government.

Revenue sharing for development of social amenities such as school, bus shelter,

parks, medical facilities, town hall, or any other public infrastructure in the local

area.

18.2.2.5. Regulatory compliance:

Relevant safety and environmental protection standards to be followed by the project

company should be outlined in the concession agreement. Even if statutory safety

monitoring departments or laws are in place, the same should be outlined in the concession

agreement.84

18.2.2.6. Return on investment and Tariff:

The primary rational for any investment by a private participant in a venture is to earn a

return on their investment. Thus it is of prime importance that adequate returns to the

84

Source: Christopher Clement-Davies, Public/Private Partnerships in Emerging Markets: Structuring the

Concession Agreement, 4

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private participant are ensured in the concession agreement. The primary area of focus

would be tariff determination and should address the following:

I. From a lenders perspective, there should be sufficient revenues to cover the

project’s debt service with a safety margin.

II. The equity investors should be assured that they will recover their investment within

a reasonable time frame and earn a reasonable return on their investment.

III. Provisions for sharing of windfall gains to ensure reasonable profit to accrue to the

Public participant if the project is more successful than anticipated.

The third point mentioned above is debatable, nonetheless it should be explored.

In the present case, MYTO II tariff regime will be applicable for the revenues of the hydro

power project. A reference of the same should be included in the concession agreement.

18.2.2.7. Adequate maintenance:

Provisions for proper repair and maintenance should be included to ensure:

That the project company generates electricity with minimized down time and

That the Hydro power project is in a good condition when it is transferred to the

government at the end of the concession period.

It is prudent for the Public Participant to require that the sponsors guarantee certain (if not

all) obligations under the concession agreement.

18.2.2.8. Key pointers for the Private Participant

The issues discussed below are aspects to be provided for in the concession agreement. The

underlying concern of all of these issues is risk allocation, which is discussed separately.

18.2.2.9. Concession period

The concession period is usually the time period for which the private sector is granted the

right to operate the infrastructure facility commercially and profit from it. Usually the

concession period is specified in terms of duration of time. However, an alternative method

is to calculate the concession period on the basis of a fixed return on investment to the

project company (that is, concession period is defined as the period of time necessary for

the private sector to achieve a specified financial return). On expiry of the concession, it is

appropriate to terminate rights and obligations rather than terminate the concession

agreement entirely.

Appropriate duration of a concession period would depend on:

The cost of constructing the facility

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The concession period is directly proportional to the cost of constructing the facility.

The concession period should be long enough for the private participant to repay the

loans and make the required return on its investments.

The cost of the process for selecting the private sector.

There is a direct correlation between the length of the process and the expense of

selecting a private participant and the tenure of the concession agreement. It may

not be cost effective to put the concession up for tender frequently.

18.2.2.10. Construction of the facility.

The primary obligation of the project company under the concession agreement is likely to

be the construction of the small hydro power project at the OMI Dam. According to

convention, it is common to confer on the private participant the obligation to design and

construct the small hydro power project.

Following issues relating to the design and construction of the small hydro power project

need to be dealt with in the concession agreement:

a. Time and price.

The cost of design and construction are usually not specified in the concession

agreement, as the project company relies on futuristic revenues from the operation

of the facility to recover its construction costs. The time limit for completion of

construction of the hydro power project should be specified in the agreement.

On failure to complete the design and construction of the facility within a specified

time, the project company should be required to pay liquidated damages. At the

same time certain rewards / bonus may be provided to incentivize the project

company to complete the construction of the facility within a specified time.

b. Government input.

The private participant would have to get the approval of the Public Participant on

the designs and other construction parameters of the facility. The concession

agreement will provide an opportunity for the government to review the design,

suggest changes where required and supervise the construction of the hydro power

project facility. There should, however, be no express obligation for the government

to approve or provide input, because this may lead to contributory fault by the

government if something is wrong in the design or construction of the infrastructure.

c. Completion.

The completion of the construction of the hydro power project is the key milestone

in the project. Mechanisms for the public participant to test whether completion of

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the power project facility has occurred, e.g. demonstrate assured electricity

generation, etc. needs to be built into the agreement.

d. Consequences of delayed completion.

Penalties to be levied if the target dates for completion of the project are not met

should be explicitly mentioned in the contract. Adequate measures to determine the

reason for the delay, i.e. failure to complete is caused by the government, the

project company (or its sponsors), or something that is outside the control of either

the government or the project company should also be determined.

e. Consequences of early completion.

The project company may be given an incentive for early completion, as that will also

mean an early commencement & availability of hydro power project. The reward for

early completion, however, may already be inbuilt if the period for termination of

the concession period is a fixed date. That is, the project company would benefit

from longer revenue generation period where the infrastructure asset is operational.

18.2.2.11. Standards

The minimum standards that the project company should comply with should be stated in

the concession agreement. The mechanisms to monitor compliance of these standards and

the consequences in the event of a failure in compliance should be in place.

The concession agreement should specify, the minimum applicable standards, the Public

Participant’s monitoring rights and the consequences of noncompliance with these

standards for each of these stages:

The design and construction phase: technical specifications for design and

construction of the facility;

On commissioning of the hydro power project: standard procedures for operation

and maintenance of the power project; and

On transfer of the hydro power project to the government: the condition of that

power project, including any warranties in relation to the components of the facility.

18.2.2.12. Tariff:

The tariff structure is the most important issue in developing a hydro power project. It

governs the economic viability of the project. The tariff for the proposed Omi Kampe

Hydroelectric power project will be in compliance with the MYTO II tariff order of the

Nigerian Electricity Regulatory Commission (NERC).85

85

Source: http://www.nercng.org/index.php/myto-2 Retrieved on 29 August 2013

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18.2.2.13. Termination:

The concession agreement in its termination provisions should specify:

The events when the project company or the public participant can exercise the

right to terminate the concession agreement, e.g. on insolvency or liquidation

events of the other party, and for material breach;

The mechanisms outlining the process of termination. Usually it is a required to

provide a notice of termination, except for termination on insolvency or cases

where breaches of the agreements are not capable of being remedied, this may

give lenders time and opportunities to exercise any step-in rights;

The compensation payments to the project company on termination. The public

participant may have to compensate the project company for the investments

already made in infrastructure facility;

Other rights and obligations of the parties after termination, such as surviving

confidentially obligations should ratified;

The lenders’ step-in rights should be reconciled with the termination provision.

Termination of the concession would not be in the interest of the lenders until

they have been paid out.

18.2.2.14. Force majeure:

Related to the issue of termination is the issue of force majeure. In general force majeure

relates to the ability of a party to excuse itself from performance of the party’s contractual

obligations where performance has become difficult or impossible due to abnormal or

unforeseeable circumstances or events that are not the fault of either party, and which the

party pleading force majeure could not avoid despite the exercise of due care.

The example of events that constitute force majeure includes

Acts of God,

War including civil war,

Revolution, coup or regime change

Riot,

Civil disturbance,

Cyclone,

Flood,

Earthquake, Tsunami

Volcanic eruption,

Tidal wave

Nuclear accident etc.

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18.2.2.15. Stabilization

The long-term nature of the concession agreement results in a risk that events would occur

that significantly change the nature of the agreement, or the assumptions that underlie the

Public Participants’ or the project company’s risks, rights and obligations under the

agreement. To address the same, the concession agreement should contain a “stabilization”

provision to deal with what happens if “exceptional events” occur. The exceptional events

may be

Changes in law or taxation,

Modifications to licenses or permits,

Economic disruption or

Loss of basic investment protection rights (however they are defined).

18.2.2.16. Dispute resolution:

The parties in the PPP should agree upon a court or an arbitral body, in whom the parties

have confidence and which can resolve any conflict or disputes in relation to the agreement

fairly. The parties also need to ensure that the final determination of the court or arbitral

body concerned is enforceable against the other party. The parties should be able to

enforce any decision in the jurisdiction in which the hydro power project is located.

18.2.2.17. Choice of law:

All disputes and arbitrations will be resolved based on the choice of law stated in the

concession agreement. It should be explicitly mentioned in the agreement that all disputes

will be subject to the Nigerian law unless otherwise agreed upon.

18.2.2.18. Performance Guarantee to Government:

In the PPP concession agreement, the sponsors guarantee to the Public Participant (and also

probably to the lenders) the performance obligations that are expected of the project

company. The actual performance guaranteed is usually limited to the obligation under the

concession agreement to complete the construction of the Hydro power project on time

and in budget.

Image 3: Performance Guarantee

Public

Participant

Concession agreement

Performance

guarantee

Sponsor Project

Company

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Key pointers for the performance guarantee:

Trigger event:

The event / breach of certain obligations that will trigger a breach of the

performance guarantee should be clearly defined.

Consequences of default:

An event that triggers the performance guarantee usually triggers a default of

another financial agreement with lenders. Hence, the interrelationship between the

project company’s (and the sponsors’) obligations to the Public Participants with the

project company’s (and the sponsors’) obligations to the lenders should be

addressed jointly.

Expiry

The time frame of a performance guarantee should be outlined. It could be a

specified number of months / years or it could be linked to the completion of

construction of the hydro power project.

18.2.2.19. Indemnity:

The performance guarantee should act as an indemnity to pay for loss if completion is not

achieved regardless of fault. Exceptions should be made for force majeure events.

18.3. Equity Finance

This segment deals with the agreements pertaining to the sponsors, or the equity holders of

the project company.

The agreements discussed here are:

The shareholders’ agreement (or SHA; includes constitutional documents of the

project company stating the rights and interests in shares, for example, the

constitution or articles of association of the project company)

The shareholders’ loan agreement; and

The options agreement.

Following a description of these agreements, the key issues from the Public Participant’s

perspective are considered.

Points to be noted by the Public Participant

The involvement of the Public Participant in the equity share holders’ agreement will be

depend upon the Public participants’ direct interest in the project company. They might

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invest in the project company for an equity share at par investment. Or depending on the

PPP parameters, the Public participant may be allotted a certain amount of free equity.

This subsection will deal with issues for the Public Participant in relation to the

shareholders’ agreement, shareholders’ loan agreement and the options agreement on

account of two cases:

Case I: if the government does not have an equity interest in the project company; and

Case II: Additional issues if the Public Participant does have equity interest in the project

company:

18.3.1. Issues whether or not the Public Participant is an equity investor:

In case the Public Participant has no direct interest in the project company, the issues that

directly impact the Public Participant are limited. It should be ensured that the

shareholders’ agreement is consistent with the terms of the concession agreement that the

Public Participant has entered into with the company. Barring this the Public participant

should not intervene in the internal management of the project company.

Some of the issues that the Public Participant may consider are:

a. Change of control:

The ownership of the project company or its control should not be allowed to freely change

hands after the concession agreement has been signed. The Public Participant would have

selected the private consortium on the basis of the reputation and experience of the

sponsors. Hence a change of control in the project company should not occur without the

government’s permission. Provisions dealing with change of control should be provided for

in the concession agreement.

The Public participant should also watch up for options agreement and shareholders’ loan

agreements that are convertible into shares. It should be ensured that the exercise of these

options do not constitute a change of control that is unacceptable.

b. Capacity.

The Public Participant should verify if the company laws in Nigeria and the constitutional

documents of the project company permit the project company to enter into the concession

agreement and to perform its obligations under the concession agreement.

c. Authority:

It should be ensured that the person entering into agreements on behalf of the project

company should be authorized to do so by the law and the constitutional documents of the

project company so as to ensure the validity of the executed documents.

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d. Information:

The Public Participant should outline the disclosure norms of the audited financial reports of

the project company and that it is informed if specified significant events occur in relation to

the project company. This will ensure transparency and accountability of the project

company with special relevance of the hydro power project that public participant provides.

e. Control:

If the Public Participant is not a shareholder, it will have negligible influence on the internal

management of the project company. Under usual circumstances, the project company

should be entitled to conduct its business without unwarranted interference from the public

participant. Nevertheless, the public participant government should insist on having some

control of the internal management of the project company, if:

The public participant / the government has provided financial guarantees to

lenders or made other financial commitments in relation to the project.

The construction of the facility has national and security significance.

In such circumstances the public participant may request for a right to nominate a director

to the board of the project company. Alternatively, it may request a right of veto for any

changes in the board of directors or senior management of the project company.

f. Priority of Payments:

With reference to the shareholders’ loan agreement, the Public Participant should ensure

that any payment due to the Public Participant by the project company, e.g. compensation

for default of the project company under the concession agreement, is higher in the Pecking

order of payments over the subordinated debt.

g. Solvency:

It is of prime importance to the public Participant that the project company is solvent. The

project company may technically be regarded as “insolvent” if subordinated debt payable

on demand of the sponsor is greater than the current assets of the project company. If

needed the optimum level of subordinate debt in the project company’s capital should be

mentioned in the concession agreement.

18.3.2. Additional issues if the government is an equity investor

The Public Participants may invest equity capital in the project company with a view to

exercise some control on the company or get a representation on the board of directors or

management of the project company. This method of gaining access or participation in the

control of the project company can be used if other forms of control through the concession

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agreement, and regulations are insufficient. In particular, it is important that the Public

Participants consider the following issues:

a. Control at the board of directors (management) level.

The Public Participant as a shareholder may have the right to appoint a director or directors

to the board of the project company. The key purpose of this will be a protection to disallow

the board to pass certain resolutions without the consent of the director at the board.

If the Public Participants hold a substantial stake in the project company, it is reasonable to

request that the minority protection issues to be decided with the affirmative vote of a

director nominated by the Public Participants. The Public Participants, however, should

consider the duties of the director nominated by them and ensure that they act in the

benefit of the company at large while ensuring that the law of the land and the principles

outlined in the concession agreement are adhered to.

b. Control at the shareholders’ level.

As a minority shareholder, the Public Participants should be entitled to certain minority

protection. This will insure that the project company would not take certain actions unless it

has the support of the public participant/ government. The public participant, as minority

shareholder, should insist on the right to veto any new issue of shares because this would

have an impact of diluting the value of the existing shareholders’ shares.

c. Dilution.

If the Public Participant has an equity interest in the project company, exercise of options

would effectively dilute this interest. This possible scenario should be reflected in the

investment price of the Public Participant equity.

d. Access to information.

If the Public Participants are shareholders, they will have access to certain information. Even

if they are not equity investors, the Public Participants should have access to periodic

financial & operational reports, as well as audited accounts/ annual financial results of the

project company.

e. Restrictions on share transfer.

The concession agreement and the financing agreements should govern the share transfer

process. Consistency should be maintained in provisions such as drag along, tag along,

transfers on default and transfers in cases of disputes across documents. The Public

Participant may also prohibit the project company from transferring shares during the

construction period of the project. Besides the statutory restrictions on share transfer

imposed by the public participant the shares in Project Company are usually transferable

subject to a right of first refusal by the other shareholders of the company.

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f. Drag along / Tag along rights.

Drag along rights.

A drag along right is the right of one shareholder to compel the other shareholders

to sell their shares to a third party along with the first shareholder. This ensures that

the shareholder with the drag along right is able to realize the investment by

enabling the shareholder with the drag along rights to deliver to a potential buyer

the whole of the project company. The details of these rights should be mentioned

in detail in the shareholders’ agreement.

Tag along rights.

This right enables one shareholder to compel the other shareholder(s) not to sell its

shares to a third party unless the second shareholders purchases, or compels the

third party to purchase also, the shares of the first shareholders. This ensures that

the shareholder with the tag along rights is entitled to the benefits of any realization

of its investment in the project company.

The concession agreement may mention its restriction or views on the Tag along and Drag

along rights of the shareholders in the project company.

g. Dispute resolution:

The disputes among shareholders in a company can be generally classified into two types:

I. A dispute relating to the interpretation or the performance of a project

agreement.

II. A dispute of commercial or strategic nature about the direction of the project

company.

The first dispute can be resolved by going for arbitration under an arbitral body or through

courts.

The second is called a “dead lock” and can be resolved in a number of ways, e.g.

By escalation the dispute to senior members of the shareholders,

Forced sale to another shareholder

Forced sale to a third party or liquidation of the project company.

The major issue with dealing with a deadlock through forced transfer mechanisms is that

such mechanisms tend to favor the party that is financially stronger.

From the Pubic Participant’s point of view, there may be legal or pragmatic restrictions on

the Pubic Participant acquiring further shares in the project company. It is generally agreed

that Silence is sometimes a way to deal with deadlocks, under the assumption that the

parties will discuss and come to a mutual compromise as it is not in any shareholders’

interest to leave the project company at a deadlock.

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18.4. Shareholders’ Agreement

The shareholders’ agreement governs the relationship between the different sponsors of

the project company. This is of importance for the Pubic Participant if it subscribes for

equity in the project company. It is also relevant for the Pubic Participant, if shares in the

project company are assignable to it by means of free equity in the bid or in the event of

default or at the end of the concession period.

A general agreement as to the individual contribution to the project and the rights and

interests of the various stakeholders in the project should be arrived at and ratified. The

agreed responsibilities and involvement of the sponsors is usually compiled in a preliminary

memorandum of understanding (MOU) or a term sheet. This MOU or term sheet should be

submitted along with the bid.

A brief on the shareholders’ agreement:

The following should be looked out for in a shareholders agreement:

18.4.1. Share capital and shareholders’ contribution.

The project company’s capital structure should be described in the shareholders’

agreement. A specific provision for the subscription of equity (and mechanics to deal with

the closing) should be present in the shareholders’ agreement. The agreement may specify

any further equity or capital commitment (in terms of the amount and form) from the

shareholders, or specifically provide that there is no further equity or capital commitment.

18.4.2. Board of directors:

With regards to the Board of Directors, the shareholders’ agreement should deal with the

following issues:

a. Appointment and removal.

Each shareholder is entitled to nominate a specified number of directors to the

board of directors the project company. The shareholders may also agree to appoint

an agreed number of “independent” directors who are not nominated by either one

of the shareholders.

b. Chairperson:

The shareholders agreement should define the procedure for appointment of the

chairperson, their tenure, whether the chairperson post will be rotated, who shall

chair the meeting if the chairperson is not present, and whether the chairperson will

have the casting vote.

c. Executive and non-executive directors:

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Depending upon the responsibilities assigned to the directors and their involvement

in the day-to-day management of the project company, the director appointed may

be executive directors (actively involved in the day-to-day management of the

project company) or non-executive directors. The shareholders agreement should

have the procedure for appointment and categorization and their compensation.

d. Meetings.

Under this the mechanism and the number of times a year the directors’ meetings

are scheduled to be held are mentioned. The procedure for calling a meeting, the

required notice of a meeting, whether electronic meetings are allowed, the rules and

requisites for the same and whether a resolution signed by all the directors is an

acceptable alternative to a meeting.

e. Quorum:

This deals with the number of directors that must attend a directors’ meeting in

order for a resolution to be validly passed. It may provide that a certain type of

director (for example a director nominated by a particular shareholder) need to

attend for a meeting to be duly convened. The shareholders’ agreement should also

provide for what happens if a quorum is not met, and quorums for subsequent

adjourned meetings.

f. Duties:

This deals with the directors’ duties and provisions to deal with conflicts of interests.

These should be synchronized with the company / corporate law of Nigeria.

18.4.3. Shareholders agreement components:

A shareholders’ agreement would deal with:

c. Meetings.

The mechanism of the general meeting, the number of times a year a meeting is

held, required notice for a meeting and the procedure for calling a meeting should

be described in the shareholders’ agreement.

d. Quorum:

In order for a shareholders’ resolution to be validly passed, the minimum number of

shareholders (in absolute numbers or in percentage of shareholding terms) that

must attend a shareholders’ meeting is called a Quorum.

The shareholders’ agreement should define the quorum and provide that a certain

class of shareholder need to attend a meeting for it to be duly convened. The

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shareholders’ agreement may also provide what happens if a quorum is not met, and

quorums for subsequent meetings.

e. Reserved matters:

Certain matters of importance need a special majority a shareholders’ meeting or a

board of directors meeting in order to be approved. Such reserved matters should be

specifically mentioned in the shareholders’ agreement.

f. Protective covenants.

The shareholders should not be able to engage in, or hold interests, that compete

with or conflict with the interest or the business of the project company. This will

apply for as long as the shareholder hold shares in the company but may apply for a

specified period of time after the shareholder ceases to hold any shares. The period

that is indefinite or unreasonably long, however, may not be enforceable because

the courts could view it as an unreasonable restraint of trade.

g. Transfers:

As there will a general restriction on the transfer of shares (at least for a period until

the completion of the construction of the facility or for longer). Transfer provisions

usually provide for:

Permitted transfers.

For example,

Transfers to subsidiaries,

Transfers subject to rights of first refusal by the other shareholders.

It is important to ensure that this exception is drafted carefully as it could be used as

a vehicle to circumvent transfer restrictions.

Compulsory transfers.

The shareholders’ agreement should state the events that trigger the compulsory

transfer of shares. This is usually the change of control of the shareholder or default

or insolvency of a shareholder. The events that trigger the transaction should be

outlined in the shareholders’ agreement.

For example,

In the case of default or deadlock resolutions as required under the

shareholders’ agreement,

In the case of a drag along rights (Please refer 9.3.2 point f.)

h. Deadlock:

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Repeated failure to meet a quorum or a repeated failure to pass a resolution at the

board or shareholders’ meeting level causes a deadlock. The usual options for

resolving a deadlock are:

The chairperson’s casting vote;

An outsider’s swing vote;

Escalation to the chairperson or chief executive of the shareholders; and

Reference to an expert or arbitration.

The choice of methods agreed upon to resolve deadlock(s) in the project company

should be mentioned in the shareholders’ agreement.

i. Exit mechanisms:

The shareholders’ agreement can provide for the permissible exit mechanism options for

the shareholders, for example; a transfer of shares, put/call option, public offering,

liquidation and sealed bids.

18.5. Shareholders’ Loan Agreement

Investors in the project company may invest by way of providing subordinated loans rather

than investing in the project as equity. The advantages of investing as subordinated loans

instead of equity are:

a. Priority:

If the subordinated loan are secured (subject to the senior debts’ priority), it would

enable the capital contribution to be ranked ahead of unsecured creditors.

b. Tax:

Payment of interest by the project company is tax deductible whereas payment of

dividends is not.

c. Flexibility:

Subordinated loans are often more flexible that share capital. It is easier to repay

the capital than the share capital. In most jurisdictions, it is also easier to pay interest

than it is to declare dividends.

Key issues:

The public participant should ensure that the shareholders’ agreement should address the

following with regards to the shareholders’ loan agreement:

a. Disallow payment of subordinate debt (other than interest until a default or after the

minimum debt service cover ratio is met)

b. Prevent acceleration and enforcement of junior debt and security

c. Allow bank to advance prior ranking new money

d. Disallow any covenants, as they would hamper a restructuring

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e. Subordinate the debt as well as the security (If the senior security fails or is

inadequate)

f. Permit the lenders to change their loan agreements or security documents

g. Compel junior creditors to co-operate in a private sale, and

h. Prevent junior creditors from instituting insolvency proceedings.

18.6. Options Agreement

The availability of options enables the sponsors to structure the project company in ways

that would achieve the objectives of the various parties associated with the project

company.

Key issues concerning the options agreement

An options agreement is an agreement between the project company and the options

holder that provides:

a. The agreement should specify the number of options provided

b. Consideration payable for the options

c. The exercise price of the option

d. The exercise period of the option, i.e. a predetermined date, or contingent to certain

events occurring

e. Lapse of options

f. The mechanism to exercise the option - the form of notice, to whom the notice

should be addressed, when the notice is deemed to have been received, etc.

g. The methodology of closing

h. Covenants prior to the exercise of the option

i. Assignment of the option

18.7. Debt Finance

The following documents in relation to providing debt finance are discussed below:

1. The loan agreement between the project company and the lenders

2. The security documents that provide security for the loan agreement, and

3. The intercreditor agreement amongst the lenders

Points of importance for the public participant:

It is the responsibility of the private participant to obtain finance for the construction of the

project and to make available working capital requirements for the smooth operation of the

project. The process for obtaining finance is likely to be of lower concern to the

government.

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The lender and donors to the project, however, are likely to be very interested in the terms

of the project company’s concession agreement with the Public Participant. Almost

invariably, lenders would require a step-in right in relation to the hydro power project

facility. This is something that needs to be discussed between the Public Participant and the

lender, despite the fact that the two parties rarely deal directly with each other but

negotiate through the project company. A direct agreement between the lenders and the

Public Participant / Government, may thus also be a part of the lending documents.

Unless the Public Participant is a party to an intercreditor agreement, it need not be

concerned with the terms of the intercreditor agreement. The Public Participant should

resist becoming a party to such an intercreditor agreement because the Public Participant’s

interests in the project company tend to be different from that of the lenders to the project.

If the same is required, then it should ensure that any undertakings do not unjustifiably limit

the ability of the Public Participant’s to exercise its rights.

18.7.1. Loan Agreement

The loan agreement between the lenders and the project company generally governs a

major part of the financing for the project company.

Key issues to be addressed in the loan agreement:

The following issues need to be considered for a loan agreement.

a. Facility:

This means information about the terms of the loan facility, including:

Commitment or Facility amount i.e. the amount of the loan.

Availability: The drawdown period of the loan and related conditions. The

project company would usually provide a draw down notice with documents as

required by the lenders to show that the conditions for draw down have been

met.

Interest rate: This is usually expressed as a formula for a quoted risk free

interest rate (e.g. LIBOR plus a fixed or variable margin).

Repayment: The repayment dates and the last day for repayment.

b. Application of funds:

The mechanism of disbursement of the loan by the project company should be stated in the

agreement.

c. Conditions precedent:

There are two types of conditions precedent to consider.

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I. First, conditions to the effectiveness of the loan agreement.

II. Second, conditions to drawdown.

Most loan agreements provide for the borrower (the Project Company) to draw down by

providing notice to the Lender, together with confirmation and documentary evidence that

the Project Company has completed its conditions of draw down.

d. Representations and warranties:

Representations and warranties are statements about the status of the project company

made by the project company. These are usually made at the date of the agreement and

repeated on each date of the draw down notice.

e. Covenants:

Covenants are undertakings by the project company to do (positive covenants) or not do

(negative covenants) certain specified things. The negative covenants are usually extensive

as it is the lenders who draft the documents.

f. Security Documents:

The security documents need to be in the required order before the draw down and is

mostly a condition precedent for the validity of the loan agreement.

g. Information rights:

The lenders would normally insist on being provided with certain information. The lenders

would have to be notified with the developments in the construction and the adherence or

deviation from the finalized construction schedule.

The lenders may request:

operating results and plans such as audited financial reports and annual budget for

the project,

Notification of delays or cost overruns in the construction process,

Monitoring rights in relation to completion tests and regulatory and environmental

compliance, and

Notification in case of any breach of the covenants.

h. Insurance:

The lenders normally require the project company to take adequate insurance cover and to

name or assign the lenders under the policies as nominees.

i. Default:

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Types of default and consequences of in the event of a default should be understood in

advance by the public participant. A distinction should be made between a serious default

that would affect all outstanding principal and interest to be payable, and a minor breach of

a covenant.

18.7.2. Security Documents:

The assets or rights given by the project company to its lenders to ensure repayment of

principal and interest of the loan can be collectively called security documents.

A characteristic of a PPP project is that physical assets in a PPP projects generally require

substantial investments to build and are extremely valuable to the project company and the

Public participant, but they may have little or no value to third parties. So lenders need to

look to a range other assets as to cover their exposure.

There is a distinction between security in favor of the lenders, which is the security to be

provided by the project company as the borrower for the loan, and security for the

performance of, e.g., a party’s obligation under the concession agreement or the EPC.

The local laws will determine for a large part what interests in the project are capable of

being used as security. The ability of the lenders to enforce its security will be highly

significant to the lender’s decision to finance a particular PPP project. From the perspective

of the lender, the important issues to consider with security are:

a. Priority:

The pecking order of payments, from the liquidation proceedings, in the event of the

liquidation of the project company should be considered.

b. Perfection of security:

Steps that need to be taken to ensure that the security interest the lender holds is capable

of being enforced in the event of default. This should be in consonance with the Nigerian

legal system.

A ‘security package’ for a typical project finance deal includes:

I. Bank accounts:

This may include an assignment of bank account, creation of a new (usually offshore)

account for revenue, arrangement to put revenues in escrow. The loan agreement

may require that the project company sets aside some of its revenues to a debt

service reserve account (DSRA) until the account balance reaches a certain point.

II. Pledges in the shares or equity of the project company:

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This can be defined as the ability to take control of the project company in the event

of certain specified defaults under the credit agreement. A “change of control”

clause is present in the concession agreement and the other project agreements to

which the project company is a party to. This is a right for the specified party to

terminate the agreement if there is a change of control as outlined in the particular

agreement.

III. Pledges in other assets:

The various other assets of the project company that may be capable of being

pledged are ancillary equipment, vehicles, land and buildings etc.

IV. Mortgage or lien:

The project company may have real estate assets that are capable of being pledged.

V. Contract assignments:

Project agreements such as the construction contracts, off-take agreements, the

concession agreement and the O&M agreements may be assigned to the lenders.

VI. Insurance:

The financing agreements will require that the project company take adequate

insurance cover. The lender will also require that they be named as a “Loss Payee”

or “Additional Insured” under the relevant insurance policy.

VII. Sponsors guarantee or undertaking:

The government may give a financial guarantee or a performance undertaking to the

project.

VIII. Public Participant / Government guarantee or undertaking:

The Public Participant may give a financial guarantee or a performance undertaking

to the project. A guarantee by the Public Participant will attract investors to the

project. At the same time it exposes the public participant to large liability whereas

the benefits of that risk would go to the private sector.86

18.7.3. Intercreditor Agreement87

An intercreditor agreement is an agreement amongst the lenders of a project company on

priority of repayment, priority on liquidation and interests in security.

The terms may include:

86

Source: http://bit.ly/1332bp0 Retrieved on 2 September 2013 87

Source: http://www.unescap.org/ttdw/ppp/otherpublications.html#energy Retrieved on 2 September 2013

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a. Appointment of a single trustee to hold debt and security for the benefit of all

creditors

b. Common terms that apply to all creditors

c. Pro rata drawdowns

d. Disbursement of payments pro rata or in agreed pecking order out of proceeds

account

e. Management and monitoring by a single agent

f. Limitation of creditor powers to vary their credit agreements

g. Voting powers for waivers and consents

h. Voting powers for default acceleration and security enforcement

i. Notification of defaults known to agents of groups of creditors

j. No action without specified creditor approvals, and

k. Sharing of recoveries pro rata or in prescribed hierarchy

18.8. Quasi-Equity Finance

Issuance of securities through the capital markets is an alternative to traditional debt

finance obtained from the banks.

Image 4: Diagrammatic representation of the Securities Issue

Points to be noted by the Public Participant

The negotiations for the issue of bonds are a very different process from negotiations for a

concession contract or even to negotiations for divesture. The terms and conditions of the

bonds are not very negotiable, and the availability of funding from the capital markets is

usually provided on a take it or leave it basis.

Some important issues from the point of view of the government as an issuer are:

Underwriting

agreement.

Project Company

(Issuer)

Transfer of asset

/ responsibilities

Terms and

conditions of

the bonds

Appointment of the

trustee

Sale of

securities

Trust Deed

Public

Participant

Trustee

Underwriter

Security holders

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18.8.1. Issuer:

The principal question is - ‘Who is the issuer?’ The Public Participant itself maybe an issuer

and in that case; it would be liable for the repayment of the interest and principal amount

for the bonds.

Alternatively, the Public Participant may transfer for the facility or infrastructure to a special

purpose vehicle (SPV), which then proceeds to issue bonds. Or, the government may be

obliged to guarantee the performance of the special purpose vehicle.

18.8.2. Liability

The issuer and often the directors of the issuer are responsible for certain statements made

in relation to the issuer. The liability applies to offering documents and may extend to

communications e.g. research reports, press releases, or other correspondence made by the

issuer during the course of the offering.

The issuer can limit its liability by:

Not deviating from the facts.

Not sharing additional information.

Not making futuristic projections or statements of intention.

18.8.3. Providing no indemnities:

No indemnity should be provided to the financial advisers or the underwriter by the issuer.

18.8.4. Lock-up:

After the subscription of an issue, the financial advisers are prohibited on the issue of new

securities and a restriction on transfer of securities by existing shareholders is in order.

Although this being a usual practice, the time frame for the prohibition should be limited.

Usually lock-up period is around 6 to 9 months, and it should not exceed one year.

18.8.5. Covenants and events of default:

These are covenants and undertakings by the issuer and are usually less extensive than

under loan agreements. Consistent between with the issuer’s plans and business operations

should be carefully reviewed.

18.9. Design, construct, Operate and Maintain88

The design, construction, operation and maintenance of the project facility entail

agreements between the project company and its various sub-contractors, consultants and

service providers.

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These agreements include the EPC agreement, Supply agreements, O&M agreement and

Insurance policies.

Key issues pertaining to the same are described below:

The Public Participant is usually not a party to any of the contracts between the project

company and its various sub-contractors. As the project company has assumed the

responsibility for the construction and operation of the facility, the Public Participant need

not concern itself with the dealings between the project companies and its various sub-

contractors. Nevertheless, it needs to ensure that the obligations imposed on the project

company under the concession agreement are being met.

The Public Participant needs to assume a monitoring role in relation to the project while

abstaining from unnecessary and unwarranted interference. The Public Participant should

request copies of the various contracts, such as the EPC agreement, the O&M agreement,

any supply agreement and insurance policies inclusive of any notices and amendments.

The cause of concerns with reference to the above mentioned documents for the Public

Participant are:

a. In the case of BOTs, or BOOTs the infrastructure to be constructed will transfer to

the government at the end of the concession period,

b. The public will pay for the project through tariffs and thus good value needs to be

ensured.

c. The contractor often has an equity interest in the project company, so the Public

Participant needs to ensure that the EPC agreement is provided on an arm’s length

basis

d. The Public Participant may be guaranteeing, directly or indirectly the performance or

construction of the infrastructure facility to the project company’s lenders

e. The contractor, the operator or the supplier may be a sponsor to the project and the

terms of providing services to the project company may not be at arms’ length.

The Public Participant should ensure that the EPC agreement, the O&M agreement and any

supply agreement and insurance policies:

a. Are at arm’s length commercial terms

b. Comply with Nigerian laws and regulations

c. Are consistent with and reflect the terms of the concession agreement

d. Require the operator to maintain the facility to an acceptable standard

e. Ensure that the infrastructure facility is in an operational condition on the transfer of

the facility to the government at the end of the concession period and that the

assets transferred include the necessary licenses.

18.10. EPC Agreement

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An EPC (engineering, procurement and construction) agreement usually caters to the largest

capital expenditure of the project company. It is an agreement between the project

company and the EPC contractor to design, construct and deliver to the project company

the infrastructure of the project. Usually BOT project are delivered on a turnkey basis.

The EPC agreement imposes on the contractor, obligations the project company has in

relation to the design and construction of the project under the concession contract.

Lenders need to be assured that the facility provided is sufficient to complete the

construction of power project within the fixed monetary limit (facility). As most EPC

agreements are provided on a fixed price and fixed time basis, it gives the Lenders the

required comfort.

EPC agreements normally contain back-to-back obligations matching those of the Project

Company under its concession agreement with the Public Participant. The project company

in effect is sub-contracting its obligations to design and construct the facility to the

contractor although the design and construction risks are not fully transferred. The Project

Company is fully liable to the Public participant for any claim against the project company

under the concession agreement, if the design and construction of the facility are not

properly executed.

The key issues to consider in an EPC agreement:

18.10.1. Project design and responsibility:

The responsibilities for the project design usually lies with the contractor. It should be

mentioned in the concession agreement that any fault in the project design remains the

responsibility of the project company. The Public Participant, through the concession

agreement, should have a right to review and approve the project design.

18.10.2. Scope of work:

Usually a contractor is engaged to construct the infrastructure on a turn-key basis, although

the responsibility of completing the same in the designated time and budget is the concern

of the project company.

18.10.3. Contract price, payment & completion schedule

This would need to be consistent with the financing agreements.

18.10.4. Key dates

The EPC agreement would set out key milestones in the project design and construction.

They usually include dates for design completion, mechanical completion and final

acceptance.

18.10.5. Performance tests

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The government should be involved in the acceptance tests to ensure that the project

performs in accordance with the standards mentioned in the concession agreement.

18.10.6. Guarantees, warranties and indemnities

The EPC would provide certain indemnities, warranties and guarantees in relation to the

facility. These indemnities, warranties and guarantees are usually limited in time, and by

the time of transfer of the facility to the government these indemnities, warranties and

guarantees. Nevertheless the benefits of any indemnities, warranties and guarantees

applying once the facility is transferred to the government should also be assigned to the

Public Participant.

18.10.7. Limitation on liability

This in affect deals with the allocation of risks between the contractor and the project

company.

18.10.8. Liquidated damages

If the contractor fails to complete the project in time, it is likely to be liable to pay liquidated

damages (LD) to the project company for this failure. The liquidated damages are a pre-

determined estimate of costs as a result of delay in completion, rather than a penalty.

18.10.9. Change orders

This will need to reflect the right of the government to change orders under the concession

agreement.

18.10.10. Defaults and remedies

What events constitute default, and what are the consequences of default.

18.10.11. Force majeure

This deals with circumstances in which the contractor would be excused from performing its

obligations under the EPC agreement. They should be in consonance with the concession

agreement.

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18.10.12. Termination

The events that lead to termination, and the consequences of termination needs to be dealt

with.

18.10.13. The FIDIC “rainbow”:

The “Red Book”, “Yellow Book”, “Orange Book” and “Silver Book” are widely used jargons to

refer to standard forms of EPC agreements developed by the FIDIC (Federation

Interriationale des Ingenieurs-Conseils or the International Federation of Consulting

Engineers). The contractors engaged in construction work commonly use these FIDIC

standard forms documents. Following is a brief description of the same:

a. Silver Book: This is a recent standard form EPC agreement which has been developed

specifically for BOT projects.

b. Red Book: The most commonly used FIDIC standard form which can be adapted to civil

engineering works.

c. Yellow Book: This is more suitable for supply of mechanical and electrical work,

d. Orange Book: This is for design-build and turnkey contracts.

18.11. Supply Agreement

These are agreements between the project company and other suppliers of the project. An

existence of a long-term supply contract at a fixed cost from a reliable supplier may

substantially reduce the risk profile of the project.

18.12. O&M Agreement

An O&M agreement (Services Agreement) is an agreement between the project company

and the operator of the hydro power plant once the project facility is completed. The

operator of the infrastructure facility may also be one of the sponsors of the project

company.

The O&M agreement will define parameters for operating efficiency and maintenance. It

usually includes penalties for failure to meet base case efficiency levels and bonuses for

exceeding them.

The terms of the O&M agreement should reflect the project company’s obligations under

the concession agreement. They should be consistent with the EPC agreement and any

supply agreement to be entered into by the project company.

The main concerns for the operation or a facility are:

the supply of inputs, e.g. utilities and other materials;

the demand for the infrastructure services; and

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the delivery of infrastructure services.

Key Terms

An O&M agreement should address the following issues:

18.12.1. Scope of the operator’s services:

This usually mirrors the operation and maintenance provisions in the concession agreement.

18.12.2. Term:

The term of this agreement should be no longer than that of the concession agreement.

18.12.3. Warranties & Performance Guarantees:

This usually mirrors the operation and maintenance provisions in the concession agreement.

18.12.4. Payment:

The calculation, timing, method and currency of payment to the operator need to be

specified.

18.12.5. Access to books and records:

The project company should have access to the books and records of operator pertaining to

the power project, particularly if the calculation of revenues or fees, and amounts to be

remitted to the project company depends on cash flow within the control of the operator.

18.12.6. Indemnification

This relates to the allocation of risks between the project company and the operator.

18.12.7. Defaults and remedies:

The consequences of a default and the remedies to the aggrieved party in case of default

should be identified clearly.

18.12.8. Force majeure:

This deals with circumstances in which the contractor would be excused from performing its

obligations under the O&M agreement. They should reflect the concession agreement.

18.12.9. Termination

The events that lead to termination, and the consequences of termination needs to be dealt

with.

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18.13. Insurance

Insurance is an instrument through which the private and public parties transfer or shift

some of the unacceptable risks of the project to insurance companies. There are many types

of insurance coverage, including casualty, third-party liability and business interruption

insurance. Insurance coverage is often limited in scope and contains wide ranging conditions

& exceptions. A cost and benefit analysis of obtaining certain insurance covers should be

considered, given that the premium for PPP related insurance policies are considerable. The

lenders usually insist that insurance policies are obtained, but the other parties may more

sensibly or cheaply cover the risks covered by the insurance policies. Some insurance cover

would be mandatory and is desirable to cap the risks involved.

18.14. Power Purchase Agreement89

A Power Purchase Agreement (PPA) ensures a steady and pre-determined payment stream

for the hydro power project. The PPA is signed between the purchaser (often a state-owned

electricity utility) and a privately owned power producer or the project company. This

agreement is the central commercial agreement for the project, setting forth the critical

revenue provisions and performance obligations. If the purchaser is obligated to pay for the

capacity and electricity, regardless of actual withdrawal of electricity, this may also be

regarded as a “take-or-pay” arrangement.

Depending on the off-takers’ credit worthiness, the presence of a long-term PPA would

significantly increase the bankability of a project because it represents a contractual

entitlement to a revenue stream.

The key elements addressed in a PPA are as follows:

a. Sale of capacity and energy - the power producer agrees to make available to the

Purchaser the contracted capacity of energy and deliver the energy in accordance

with the PPA

b. Charges for Available Capacity and Electrical Output

c. Permission for Third party sales/ Exclusivity provisions

d. Force majeure or purchaser breach of contract

e. Testing regime

f. Termination

g. Provision for change of law, taxation and its implications

18.15. Implementation Agreement (IA)90

Implementation agreements outline the contractual obligations and undertakings between

the Government and the supplier or project company. The government may not usually be a

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direct party to the power purchase agreement. Installing a power plant often requires

assistance from the government in various capacities such as:

a. Obtaining required consents & licenses

b. Undertaking to ensure that the utility performs its obligations (sometimes in the

form of a guarantee) where there is a concern on the part of the supplier that the

utility might not or may not have the financial standing to fulfill its obligations.

c. Undertakings from the government on export and import duties and taxation of the

supplier.

The implementation agreement usually includes undertakings by the supplier to the

government regarding Compliance with environmental laws.

18.16. Connection to Grid / Power Pooling Arrangements91

Interconnection, Grid Connection or Power Pooling Agreement is mandatory in Public

private partnerships concerning power projects. These contracts outline the responsibilities

and fees for connecting the power generated by an independent power producer (IPP) to

the owner of grid system, generally a public entity.

18.17. Land Lease Agreements92

These agreements have come into play when the power projects are to be constructed on

land not owned by the project owning company. The land owners, private or the

government, lease or sell the land to the operating company or concessionaire for the

period of the concession contract. In an independent power project, the Land Lease

Agreement could be a stand-alone agreement, or its main provisions can also be included in

the Power Purchase Agreement or Implementation Agreement (in case of government

owned land).

18.18. Government support agreement

Often, the host government will be required to provide financial or other support to a

project. The terms and conditions will be set forth in some type of government support

agreement, such as a payment guaranty or an implementation agreement.

18.19. Other Agreements

Other ancillary agreements are also customarily entered into, such as a land lease

agreement (or land purchase agreement), sponsor support agreements, security

agreements, an escrow agreement and warranties and warranty bonds. The particular facts

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and circumstances of each transaction may additionally require further ancillary agreements

between the relevant parties.

19. Option analysis

Option 5: Maintain Status quo.

Option Explanation: This simply means that the Omi Dam should be left in its current

condition as it is. This option calls for no further investment or any development of the

available infrastructure.

Impact on Public Participant

Economic Impact: The proposed Omi Kampe Hydroelectric power project has a potential to

deliver earning with an NPV of around 1.03 million USD (see section 13.9). If the project is

not developed, the Public participants lose out on a potential revenue stream.

Social Impact: The primary objective of Public Participants is considered to work towards

the development of the society at large. Nigeria at present faces severe electricity outages

and shortages (see section 6) and the area around the Omi Dam is not an exception. The

proposed 2.0 MW Hydro power project at the Omi Dam if developed will help the public

participants in bringing much needed electricity to the region around the Omi Dam.

Impact on potential Private Participants:

The proposed Hydro power project at the Omi Dam is a viable project and has a potential to

deliver an IRR of around 20.0% to its investors after factoring for all the payables to the

Public participant. If the Status Quo is maintained, the investors will lose an opportunity to

invest in a profitable and viable project.

Impact on General Public:

According information shared by the staff at the OMI Dam during the site visit, the Omi Dam

is not being used to its optimum for irrigation works. A few of the gates of the dam are not

functional and the flow of waters from the dam into the canal network is not being

regulated or gauged. If the proposed hydroelectric power project is not developed, the

public will not get any electricity that can be harnessed from the dam. Hence, maintaining

the status quo will result in losses to the public on both fronts; first from the non-

functioning irrigation and secondly from the loss of potential power generation form the

dam.

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Option 6: Government / Public Participants Develop, Construct and operate the

project:

Option Explanation: This option entails that the proposed hydro power project at the Omi

dam is built using public funds and resources.


Economic Impact: Investing scarce public funds for the developing the project as opposed to

gaining from the upfront premium and receivables from the private participant is not

advisable. Also the public participants may not have the required technical resources to

develop the hydro power project. Secondly the management of the project during

development, construction and operation by the public authorities when compared with the

private participants may not be considered efficient.


If the project is developed by the government using public funds, the private participants

will be devoid of an investment opportunity.

Impact on the General Public:

In developing countries around the world there have been many a cases of mismanagement

of infrastructure assets by public utility companies. This results in a loss to the public

exchequer on one side, and a general discomfort and lack of services to the general public.

It is difficult to impose a penalty on a public body executing the project for any

discrepancies, malfunctioning or delays in project execution as opposed to imposing them

on a private participant.

Keeping in view the above mentioned, it may not be advisable for the project to be

executed by the Government / the Public participants.

Option 7: Privatization of the proposed project including the ownership of the Omi

dam.

Option Explanation: This option entails the lump sum sale of the Omi Dam and the right to

construct a hydro power project on the dam. This will give the private participant absolute

water abstraction rights, and control over the dams’ operation and maintenance.


Economic Impact: This option may result in substantial upfront monetary benefits for the

Public participant, but they lose ownership of the assets and also lose out on long term

benefits from the project.

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Social Impact: The government/ public participant will lose its ownership and subsequently

the right to monitor the maintenance and upkeep of the dam.


Purchasing the OMI dam for a 2.0 MW hydro power project will render the project

financially non-viable and will not be a preferred option by any investor / project developer.


Besides a profit motive, private participants have little incentive for the upkeep and

maintenance of an asset. Any malfunction in the dam can have disastrous consequences for

the people residing downstream of the dam.

Option 8: Development of the hydro power project via the PPP mode.

Option Explanation: Under this option the private participant is granted the option to

develop the small hydro power project at the OMI dam. The ownership of the existing

structures pertaining to the dam remain with the government and only the ownership of the

new structures constructed for the hydro power project are transferred to the project

company.


Economic Impact: The project shall be allotted on the basis of a bid (see section 13.9). The

private participant will invest all the monies required to develop and construct the project.

The public participant will gain from the project depending upon the bid type; upfront

premium, free power, free equity, least concession period or a combination. This results in

the Public participant gaining one from the bid (monetary benefits) and secondly the larger

gain is in getting the project developed through a competent and experienced power

project developer.

Social Impact: Developing a project via the PPP mode will help the Public participants in

achieving their objective of development of infrastructure assets for the general upliftment

of living standards of the people in a cost effective and efficient manner.

Impact on Private Participant:

The Omi dam is a viable project capable of rewarding its investors with substantial returns.

A PPP mode of development will provide both the public and the private participants with

enough incentives to assist each other to develop the project.


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The development of the proposed Omi hydro power project will result in the upliftment in

the quality of life of the people residing in and around the area. The benefit that will accrue

will be three pronged:

a. During construction the Project will provide employment to the people in the

vicinity.

b. Post commissioning 30% of the revenue generated by the project will be shared with

the Hydroelectric Power Producing Area Development Commission, thus providing a

long term stream of funds for the development of the area.

c. The construction of the power project will lead to the optimum utilization of the

precocious natural resource and utilize the energy generation potential created by

the Omi dam currently facing a state of neglect.

Three primary criteria of evaluation are identified for choosing the best possible option:

4. Electricity being made available for the public

5. The government should invest the least possible resource (financial and manpower)

6. The option should be lucrative financially for Private Sector investments

Assigning weights for each of the above mentioned three criteria the following chart is

developed:

Image 5: Diagrammatic representation of results of the various options analyzed

Keeping the above mentioned observations of the various options, and the chart shown

above, option 4, i.e. development of the proposed hydro power project at the Omi dam via

a PPP methodology is the most favorable method of developing the hydro power project.

0

1

2

3

4

5

Option 1

(Status Quo)

Option 2

(Govt. Invests all funds)

Option 3

(Pvt. Participant takes

over the dam)

Option 4

(Private Public

Partnership)

Electricity for the Public

Government should invest

the least possible resource

Financially lucrative for

Private Sector investments

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20. Project Implementation Arrangements93

and Evaluation Criteria for selection of

Private Sector

A number of steps are involved in the project implementation process from conception of a

project to allotment of a PPP concession to the selected bidder. Each step requires careful

planning and a dedicated team of experienced professionals for flawless implementation.

The various stages envisaged in executing a PPP are summarized in the flow chart below:

Image 6: Stages in Project Implementation for PPP of a Small Hydro power project

Develop the project for the bid94

After identifying any project for a PPP, the Public Participants need to define all aspects of

the Project before it can be advertised to potential investors. The following steps give a

comprehensive outline of the project definition process:

I. Assess the requirement and assemble the requisite project management team and

external advisers.

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Project Implementation Process

Project Identification & Definition

Project Structuring

Procurement notice, prequalification and shortlisting

Invitation to Tender

Interaction with Bidders

Evaluation of tenders and award of PPP Contract

Monitoring of Project Implementation till commissioning

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II. Define the extent of Public participation & Identify the various parties comprising the

Public Participant

III. Outline individual roles and responsibilities of public participants

IV. Establish communication protocol among the public participants.

V. Establish the Public Participant’s requirements from the hydro power project and

outline the contractual documents governing the same

VI. Develop confidence among potential private participants on the terms envisaged

VII. Internally assess and determine type of public sector support that will be provided to

the private participant pre and post – commissioning e.g. support for land

acquisition, regulatory clearances such as Environmental clearance.

VIII. Outline and draft a comprehensive and credible PPP / concession contract

IX. Identify potential areas of dispute and establish the basis for dispute management

X. Develop the project information for bidders and establish a data room

XI. Identify and list all the relevant statutory processes and clearances required

XII. Develop a strategy for raising awareness of the project among potential investors

e.g. a road show, pre-bid meeting, call for expression of interest (EOI)

XIII. Prepare for the procurement phase (strategy, budgets, timetable, and people)

XIV. Complete the value-for-money assessments

XV. Establish the basis on which a project’s success will be evaluated

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Image 7: Flow of Information & number of Bidders

20.1. Communication with bidders

Communication with bidders is a continuous process and needs to be strategized, planned

and implemented at various stages of the project. The common points of communication

are:

Market soundings during project development

Market briefing held to inform the potential participants at the time of the release of

the EOI.

Communication during the RfQ and RfP phase that comprise of written Question and

answer procedures

Communication during the bid phase that involves an interactive tender process;

Debriefing of unsuccessful parties once contract execution or financial close is

achieved.

Release of bid security of unsuccessful bidders once negotiations with preferred

bidder are concluded successfully

PPP projects may require a greater window of opportunity for bidders to seek clarification

and advice in comparison to other projects.

Project launch

Prequalification

Competitive negotiation and

dialogue

Request for proposals

Selection of final or preferred

bidder

Financial close

Number

of

Bidders

Detailed

information

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It should be ensured that:

Confidentiality of information shared by all bidders is maintained.

No bidder receives an unfair advantage as a result of elaboration given in response

to a question (responses to clarifications are therefore to be shared equally with all

bidders irrespective of who asked for the clarification)

Relevant transparency measures are sufficiently followed in letter and spirit

Image 8: Preparation of a Project for a PPP95

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Pre

pa

rati

on

of

Pro

ject

fo

r P

PP

Project Management Assemble project team and

governance arrangements; Develop

risk register for project management

Tender phase preparation Prepare Procurement phase

management

Project marketing Assess initial market awareness

Readiness for market Assessment of Outline Business Case

Assignment of revenue stream Defining Scope of

projectEscrow Agent

Define the scope with respect to

legal, technical, environmental, and

social issues concerning the

Cost benefit analysis

Insurer

Outline the various project costs in

detail and compare with the potential

project revenueOperator

Project Risk analysis Identification, allocation and

mitigation of project risks

Potential investor market

analysis

Gauge interest of potential funders

and contractors and adjust the project

scope accordingly

Project documentation Prepare project documents e.g. Feasibility

studies, hydrology reports, other technical

parameters along with concession terms

Stakeholder management Assess Stakeholder views and

incorporate in the project

Value for money Analyze Value for money In

terd

ep

en

de

nt

Fact

ors

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20.2. Procurement notice (expression of interest)

The formal procurement process starts with a publication of the public procurement notice.

This marks the start of the formal procurement process. It is a good practice to publish the

procurement notice in one or more of the local and international periodicals, as well as on

reputed websites. Also known as an Expression of Interest (EOI), this is a multi-staged

process used to shortlist potential suppliers/contractors/ private participants for the

requisite works. The shortlisted parties later submit a detailed bid in the tendering stage.

The purpose of the procurement phase is to develop and conduct a process that

accomplishes the following:

Selects a bid

Maximizes the benefits of competitive tension between bidders

Delivers the best bid from the most competent bidder

Minimizes time and cost

Stands up to scrutiny from citizens and both the public and private sectors.

An EOI should usually comprise of the following96

:

Name and full address of the Organization:

Management Structure:

Contact Person with designation:

Contact details (telephone numbers, fax number, email):

Current operational areas of work of the investor group:

Audited financial statements / Turnover for the most recent three years:

Approval/registration with any Govt. or international agency:

Details of expertise available in the design, construction and operation and

maintenance of hydro power projects

Regular manpower available on roll for proposed work along with their age,

qualification and experience

Description of similar projects executed till date in different geographical areas

Any other credentials in the field of hydropower

Acceptance of terms and conditions

20.3. Pre-Qualification and Request for qualification (RfQ)

The primary purpose of a prequalification is to include bidders that appear to be capable of

conducting the PPP project in the requisite manner. The description of the project

mentioned in the notice to the private participants should be broad and generic so that, it

need not be altered subsequently, as that may lead to the procurement process being

required to start all over again. At the same time, the description should not be so broad as

to confound the bidders regarding the specific scope of the project.

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Usually, interested parties that respond to the initial notice are intimated with a statement

of information about the project along with a questionnaire. The responses form the basis

of a qualification criterion that demonstrates the parties’ ability to implement the project.

The prequalification questionnaire should address the following:

A description of the dam facility and an outline and overview of the proposed hydro

power project;

The upfront fee (refundable and non-refundable) to be submitted (e.g. tender

document charges, processing fee, security deposits);

The intended allocation of major risks and envisaged responsibilities of each party;

A summarized list of the studies and data (such as feasibility studies, hydrology

reports & data, structural report & drawings for the dam, historical readings from

various monitoring devices on the dam) that will be made available to bidders

concerning the project;

the intended procurement process;

A description of the minimum qualification criteria for financial threshold (net worth

and turnover) and technical competence/ qualification in terms of hydro power

projects executed;

The tie-up / Joint ventures / consortium allowed (if any) (e.g. parent or subsidiary

companies’ qualifications);

The historical business activities of the consortium and legal information about their

constituents;

The qualifications of personnel involved in the project;

The criteria and mechanisms that will be used to evaluate the prequalification

statement

A time table covering various events of the bid.

Usually the public participant’s legal advisers draft both the PPP procurement notice and the

prequalification questionnaire (also called the RfQ).

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Image 9: Outline of the Prequalification Phase97

20.4. Shortlisting

The objective of shortlisting is to reduce the number of bidders. While the actual reduced

number of bidders varies from project to project, the usual number of bidders left after the

shortlisting is generally between three and five. Evaluating bids is a time-consuming exercise

for the public participants and its consultants. The aim of the bidding process is to maximize

competition and not the number of bidders.

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Pre

qu

ali

fica

tio

n p

ha

se

Assemble Team

Launch and market

the Project

Request for

prequalification (RfQ)

Share project

information

Response Evaluation

Short list Selected

bidders

Identify and appoint

procurement management

team & transaction advisers

Market and advertise the

project, invite requests for

prequalification documents

Issue prequalification

documents

Issue project information

memorandum

Arrange site visits and bidders’

conference, as necessary, and

respond to bidder inquiries

Evaluate RfQ

Compile a bidder short list

External legal,

Technical,

financial advisory

support to

prepare

prequalification

documents &

evaluate

responses

Quality

Assurance

Review

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The short listing procedure will focus on the technical capability, business capability and

financial net worth of the potential bidders. These capacities must be, in principle,

demonstrated jointly, rather than individually, by the members of a consortium.

The various stages of the prequalification and shortlisting process can be summarized as

below:

Stage I: Determine which consortia have passed the thresholds in all the relevant aspects

Stage II: Rank and assign scores to the parties clearing stage I on the basis of a systematic

and predetermined process.

Stage III: On the basis of ranks obtained in stage II narrow down the list to arrive at a

shortlist.

A well-substantiated prequalification report should be prepared to provide a good audit

trail. Unsuccessful bidders should be debriefed.

20.5. Invitation to tender/bid or Request for Proposal (RfP)98

20.5.1. The Request for Proposal

The tender documents are usually prepared during the last stages of the project preparation

phase. However, finalization of various documents often takes place during the

prequalification period.

It should be ensured that the various consultants (finance, technical, legal) provide their

individual inputs in detail and then re-examine the final documents as a whole to ensure

that the various components of the tender documents are in sync with each other. It should

be ensured that the bids should be comparable and there is no ambiguity or room for

debate on any of the inputs by any bidder.

The tender documentation should address the following issues:

A detailed information memorandum about the project should be provided;

A summary of the obligations of each party and the risk allocation;

Detailed output specifications

The minimum required technical design, technical features and the international or

local design specifications / codes to be adhered to

The level of commitment required from the lenders and equity investors

The full draft PPP contract

The Instructions to Bidders (ITB) concerning all the information they must submit

and the detailed procedures for submission including formats, number of copies,

deadlines;

The evaluation criteria; and

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The requirements for bid bonds or security (amount, form).

The information shared in the tender document shall be detailed to assist the bidder and to

minimize the bidding costs for the private candidates, however it shall not:

Prevent bidders from offering cost-efficient alternatives based on their expertise and

capacity for innovation,

Transfer unnecessary risks to the public entity.

20.5.2. Data Room

Following release of the RFP to the shortlisted bidders, a key aspect involves the

communication protocols, and in particular, sharing of the data. For this a Data room is

proposed to be created. The process can be made more efficient by providing the

shortlisted bidders all relevant information that may aid in the preparation of the response

to the RFP.

Such information may include:

Any analysis of legislative and regulatory impacts;

Feasibility studies & other technical data;

Land use considerations;

Geological information;

Demand estimates etc.

Information in the data room should be made available with appropriate disclaimers. This

data room may be a physical room or an electronic equivalent (e.g. online repository with

access control and printing permissions/ restrictions. The information could be shared with

the bidders as part of the RFP documentation as well.

20.5.3. Interaction with the bidders

The RfP stage involves a submission of bids from prequalified bidders within a notified

timetable. The submission of documents may be preceded by a round of the prequalified

bidders seeking clarifications about the bid requirements. Written clarifications should be

provided to all bidders. Clarification meetings may also be held with representatives of all

bidders being invited to attend. Written communication should be issued detailing minutes

of such meetings and the resultant clarifications.

The terms and conditions for the interactive process outlining the procedures, protocols and

rules should be pre-determined in the set of conditions, rights and obligations to which

bidders agree to. The objective of developing this iterative process is to improve the quality

of the proposals by:

Promoting and encouraging innovative solutions from different bidders;

Clarifying any technical, financial and commercial issues; and

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Providing timely, direct and specific feedback to all bidders on key aspects of

their bids.

The end objective of sharing adequate data and the interaction process for providing

clarifications is to improve the quality of bid submissions from the shortlisted bidders and

ultimately deliver better outcomes for the public.

Re

qu

est

fo

r P

rop

osa

l (R

fP)

ph

ase

Re

gu

lato

ry c

on

tro

ls

Share detailed project

information

Receive detailed

proposals for

evaluation from

Bidders

Evaluation of

proposals and

selection of winning

bid

External legal,

Technical,

financial advisory

support to

prepare

prequalification

documents & to

evaluate

responses

Quality

Assurance

Review

Fin

ali

ze t

he

Bid

Tra

nsf

er

of

infr

ast

ruct

ure

ass

et

Choose

preferred

bidder

Conduct

lenders’ Due

Diligence

Issue project documents to

short-listed bidders

Issue request for proposals

Conduct

clarification

Meetings

Conduct

competitive

Dialogue

Evaluate final proposals from

bidders develop evaluation and

value-for-money reports

Execute concession

agreement

Confirm winning bid

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Image 10: Outline of the Request-for-Proposals and Financial Close Phases99

20.6. Documents to be submitted by bidders100

The documents to be submitted by the bidder can be divided into four parts, namely: the

Technical bid proposal, the Financial Proposal, the Legal Proposal and the draft contracts.

20.6.1 Technical bid proposal

The finalizing of contractors, sub-contractors and suppliers prior to the bid is an additional

and unnecessary burden on bidders and should not be compulsory. These can be identified

once the concession has been awarded. The technical bid should comprise of the following:

Relevant technical experience (individual or consortium) in designing and

constructing dams, irrigation schemes and hydro power projects

Environmental protection plan

Operating program and costs

Maintenance program and costs

20.6.2 Financial proposal

The commercial / financial proposal should address the following issues:

The financial net worth of the bidder

The turnover of the bidder or the parent company(s) of the proposed project

company

The free cash flows of the bidder or the parent company(s) of the proposed project

company.

Residual value/debt amortization profile.

20.6.3 Legal proposal

The bidder should submit the following along with the bid:

Acceptance of terms of the contract,

Draft shareholders' agreement/ consortium agreement/ joint venture agreement

Letter of conveyance signed by the authorized representatives of the company or

consortium submitting the bid.

Term sheets of other main contracts could also be requested (power purchase

agreement, construction contract (EPC), operation & maintenance contract,

minimum insurance requirements).

20.6.4 Draft Contract

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The bidders should be expected to submit a draft copy of the contract along with the bid.

This will affirm their compliance with the terms of the contract and limit post selection

negotiation to a reasonable minimum. Draft contracts could be provided as formats along

with the Tender Documents and bidders may be required to provide their mark-up of the

contracts. E.g. Draft PPA could be provided along with the Bid to be marked up and

submitted by the bidders with the response. Bidders may be encouraged to accept most of

the terms and submit a non-marked up or least marked up bid. Markups of different bidders

then can be compared to see who has submitted the most responsive (least marked up) bid.

20.7. Bid Evaluation and Negotiations:

20.7.1 Bid Evaluation

After the tenders (responses to RfP) are submitted, the bids are scrutinized and evaluated to

select the preferred bidder. Bids should be evaluated in line with the evaluation criteria

detailed in the RFP and in accordance with the details of the evaluation plan. An evaluation

plan should be developed and approved by the Project Steering Committee before the

release of the RFP responses.

Once the RfP responses are received, the decision is made on the appropriate structure of

the evaluation team. Different teams are established to assess the service delivery, design

solution and commercial elements of proposals. A matrix is usually created to rank the

various bidders in the order of the inputs in the bid and arrive at the ‘L1’, ‘L2’ and ‘L3’.

It is imperative that any bidding consortium must come across as a well-integrated entity

rather than just a collection of individuals together solely for fulfilling the bidding purposes

requirements.

20.7.2 Low Bid response

The method to proceed in case there is only a single applicant for the bid should be pre

decided and outlined. If the bidder interest is low because of lack of information in the

tender documents, it should be analyzed if these can realistically be remedied. The best

solution might be to repeat the tender procedure after addressing the deficiencies.

20.7.3 Negotiations101

If the circumstances allow, instead of taking a “best and final offer” (BAFO) from the

bidders, it may be beneficial to undertake negotiations simultaneously with two or more

bidders before the evaluation process and selecting a preferred bidder.

If the ‘Bid Evaluation Panel’ concludes that the bidders need to develop their proposals to

standards that justify their appointment as preferred bidders, pre-selection negotiations

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should be conducted. A higher level of interaction may be required to resolves issues as the

assessment (e.g. design, commercial or otherwise) will require interactive discussions. Such

pre-selection negotiations should be undertaken within a tightly defined timeframe to

maintain the competitive spirit of the process and to minimize bid costs.

The pre-selection negotiations, if conducted, should address all areas of deficiency in the

bidder’s proposals e.g. design, construction, services, financial, contractual among other

things. The bid evaluation panel may choose to negotiate different risk allocations and

contractual terms with each bidder, provided that the process is conducted in a fair and

equitable manner, under the eyes of an independent watchdog or regulator.

20.8. Evaluation reports

The evaluation process and methodology used for assessing the submitted bids or proposals

should be included in the form of an evaluation report. The format for the same should be

specified in the evaluation plan and should be agreed by the steering committee before

proposals are received. If the evaluation committee is assisted by a range of specialized sub-

committees, separate evaluation reports should normally be compiled by each sub-

committee.

Each of the reports should be combined into a combined evaluation panel report for the

Project Steering Committee. The report should rank the bids from in a decreasing order of

preference based on clearly identified & pre-decided parameters such as cost, value for

money, technical efficiency or qualification of the proposal. The report should specifically

address the evaluation criteria mentioned in the EOI/RFP. It should make an objective and

analytical analysis of the bids, based on the identified evaluation criteria (e.g. service

delivery) and make an unambiguous recommendation of the preferred party to the

Government.

The report should discuss the rankings within each area of evaluation and the basis for the

procurement team’s agreement on the preferred bidder. The evaluation process and report

should also include a confirmation from an independent process watchdog or regulator that

the evaluation process was undertaken in accordance with the evaluation plan and has been

conducted in a fair & transparent manner.

20.9. Award

The Steering Committee should ensure that a single preferred bidder is nominated within

the stipulated timeframe. If it is not possible to identify a single preferred bidder after the

evaluation phase, the Project Steering Committee should evaluate if a value for money

solution can be achieved. Only then the Project Steering Committee may agree to an

alternative approach to identify a bidder as preferred through:

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Shortlisting two bidders and undertaking a best and final offer (“BAFO”)

negotiation; or

Shortlisting two bidders to undertake a structured negotiation process where

a greater level of interaction is involved to address the outstanding issues.

It should be ensured that a minimum ‘standstill period’ (say 15 days) is maintained between

the PPP contract award decision and the actual conclusion of the contract. This will allow

the rejected bidders time to conduct their assessment and decide if they want to challenge

the award. The Public participant should structure a mechanism to address all grievances of

any aggrieved bidder. Otherwise, they may take steps to hinder/delay the execution of the

project or in worst case have the PPP contract rendered ineffective.

20.10. Bidding timelines:

Indicative timelines for all stages of the bid have to be planned well in advance and

communicated to the bidders at the start of the bid process. The man-hours required in the

analysis of the proposals received should be correctly estimated and appropriate allocation

of manpower should be done. While it should be ensured that there is enough time to

complete the assessment procedure, the time lag between two events should not be so long

as to dampen the interest of the bidders or give them time to indulge in unfair practices.

The following table gives an indicative time schedule for the various events in the bid:

Day --> 0 30 60 75 90 120 180 210

RfQ

Request for Qualification

(RfQ)

Submission and opening of

Response to EOI / RfQ

Evaluation of RfQ for Short-

listing potential bidders

RfP

Invitation to tender/bid (ITB)

or Request for Proposal

Pre-bid meeting /

Interaction with the bidders

Submission of Response to

RfP

Evaluation of responses to

RfP

Award of PPP contract

Standstill Period

Execution of the contract

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21. Implementation Plan

A Project Implementation Plan is prepared to outline the activities required to be

completed during the implementation of the project. This is a detailed list of the pending

studies, procurement milestones, documentation and other tasks required to bring the

project to completion. The proposed project implementation plan for the proposed

hydro power power project at the Omi dam starting from Day ‘0’ is shown in the table

below:

Sr.

No.

Information to be covered in

the implementation

schedule

Timeline

(Months)

Start Date End Date Responsibility

1

Additional studies required

before commencing

procurement

List of study to be performed

a) Triaxial test:

b) Consolidation

(Oedometer) test:

c) Permeability test

d) Angle of Repose Test

e) Stability Analysis Factor of

Safety check

f) Sedimentation in the dam

5 - 6 0 150 - 180 Public

Participant

g) Hydrology data collection

(Discharge into and out of

the Omi dam)

12 - 18 0 360 - 540 Public

Participant

2 Timeline for Preparing the

Tender Documents

First draft of tender

documents and other key

project documents

6 0 180 Public

Participant

Timetable for approval of the

OBC 6 0 180

Public

Participant

3 Pre-qualification RfQ

Issue Request for

Qualification 1 180 210

Public

Participant

Submission and opening of

Response to EOI / RfQ 230

Private

Participant

Evaluation of RfQ for Short-

listing potential bidders 0.5 260 275

Public

Participant

4 Invitation to tender/bid (ITB)

or Request for Proposal 275

Public

Participant

Pre-bid meeting / Interaction

with the bidders 290

Public

Participant

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Sr.

No.

Information to be covered in

the implementation

schedule

Timeline

(Months)

Start Date End Date Responsibility

Submission of Response to

RfP 320

Private

Participant

Evaluation of responses to

RfP 320 380

Public

Participant

5 Award of PPP contract

380

Public

Participant

Standstill Period 1 380 410

6 Execution of the contract

410

Public

Participant

7 Obtaining clearances 12 410 770 Private

Participant

Arranging and finalizing

finance 6 590 770

Private

Participant

8

Construction timeline (for

projects that involve a capital

expenditure component)

24 770 1,490 Private

Participant

9 Testing and commissioning 3 1,490 1,580 Private

Participant

10

Expected day for

commencement of

commercial operations

1,580

Private

Participant

22. Project resource requirement

The project development will entail substantial interaction of the Public authorities and the

Private participants. The key responsibilities of the Public participant through the various

stages of the project development can be classified as follows:

a. Project implementation process

Conducting the various pending technical studies and test

Collection of hydrological data

Preparation of the various bid documents

b. Bidding stage

Make available a data room with all information needed by the bidders

Sale of tender / bid documents at various stages

Bid evaluation at various stages

Finalizing the winning bid

Negotiating the contract

Awarding the contract

c. Post Project allotment: Project development phase

Monitor the developments of the project developer

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Provided assistance where ever needed or committed

Ensure timely completion of project milestones

d. Post Project allotment: Construction phase

Monitor the quality and various milestones of construction

Ensure fair and best practices are followed in construction methodology

e. Post commissioning

Check project performance parameters

Ensure best Operation and Maintenance practices are followed

The above mentioned activities are not exhaustive, and government will have to commit

resource in the form of

a. Financial resources

b. Dedicated skilled manpower to attend and address the communication

with the Private participants

c. Liaison personal

d. Specialists and Consultants

Lawyers

Financial Consultants

PPP Expert

Technical consultants etc.

In addition to this the Public participant will have to establish a robust and effective

communication system between the various concerned government departments by

establishing nodal officers in each department to facilitate smooth and efficient flow of

information between the various departments.

23. Conclusion and Recommendations on Structuring

Based on the reasoning stated in the above sections, a Public Private Partnership is

estimated to be the most efficient method of developing the proposed hydro power project.

Among the various PPP structures available the BOOT (Build – Own – Operate – Transfer)

has been envisaged to be the most effective PPP structure.

The Public participant will have to establish a competent and efficient team to complete the

pending data collection, formulate the various bid documents required, conduct the bid and

choose the most efficient and capable bidder for the project. Nodal officers will have to be

established in each of the concerned departments to ensure a seamless and effective

communication network.

The key to success to executing the proposed hydro power project at the OMI dam lies not

only in formulating profitable bidding strategies and selecting a capable developer, but

monitoring efficiently all the stages of from project development, construction and post

commissioning.

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24. List of appendices

Appendix A1 List Of Collated Documents Used As Sources Of Information.

Appendix A2 Review & Comments on the Omi Dam and its appurtenant Structures

Appendix A3 Review of the current status of the dam and its appurtenant structures

Appendix A4 Detailed cost estimates of the proposed Omi Hydro power

project:

Appendix A5 Financial model: Assumptions

Appendix A6 Financial model: Financial Results

Appendix A7 Types of Public Private Partnerships (PPP)

Appendix A8 Participants in the Public Private Partnership